Edgar Filing: GENESIS ENERGY LP

424B3

Filed pursuant to Rule 424(b)(3)
Registration No. 333-203259

The information in this prospectus supplement and the accompanying prospectus is not complete and may be changed. This prospectus supplement and the accompanying prospectus are not an offer to sell these securities, and we are not soliciting offers to buy these securities, in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED JULY 16, 2015

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus dated April 6, 2015)

9,000,000 Common Units

LOGO

Genesis Energy, L.P.

Representing Limited Partner Interests

We are offering 9,000,000 common units representing limited partner interests of Genesis Energy, L.P.

Our common units trade on the New York Stock Exchange under the symbol “GEL.” The last reported sale price of our common units on the New York Stock Exchange on July 15, 2015 was $46.49. Unless the context otherwise requires, references to common units in this prospectus supplement refer to the Common Units — Class A under our partnership agreement.

Investing in our common units involves risks. Read “Risk Factors” beginning on page S-21 of this prospectus supplement and beginning on page 2 of the accompanying base prospectus.


	Per Common Unit	Total
Initial price to the public	$	$
Underwriting discounts and commissions	$	$
Proceeds, before expenses, to Genesis Energy, L.P.	$	$

We have granted to the underwriters a 30-day option to purchase up to an additional 1,350,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 9,000,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying base 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 July , 2015.

Joint Book-Running Managers


Wells Fargo Securities		BofA Merrill Lynch		Citigroup


Deutsche Bank Securities		Barclays		Credit Suisse		UBS Investment Bank


Raymond James		RBC Capital Markets		BMO Capital Markets

Co-Managers


Oppenheimer & Co.		Baird		Janney Montgomery Scott

Prospectus Supplement dated July , 2015.

TABLE OF CONTENTS

PROSPECTUS SUPPLEMENT


	Page
SUMMARY		S-1
RISK FACTORS		S-21
USE OF PROCEEDS		S-25
CAPITALIZATION		S-26
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS		S-27
UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL DATA		S-28
ENTERPRISE OFFSHORE BUSINESS		S-40
ENTERPRISE OFFSHORE BUSINESS SELECTED FINANCIAL DATA		S-45
ENTERPRISE OFFSHORE BUSINESS MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		S-46
MATERIAL TAX CONSIDERATIONS		S-50
UNDERWRITING		S-53
LEGAL MATTERS		S-58
EXPERTS		S-58
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS		S-59
WHERE YOU CAN FIND MORE INFORMATION		S-61
INDEX TO COMBINED FINANCIAL STATEMENTS		F-1

PROSPECTUS DATED APRIL 6, 2015


	Page
ABOUT THIS PROSPECTUS		1
GENESIS ENERGY, L.P.		1
RISK FACTORS		2
USE OF PROCEEDS		2
RATIO OF EARNINGS TO FIXED CHARGES		3
DESCRIPTION OF OUR EQUITY SECURITIES		4
General		4
Our Common Units		4
Our Preferred Securities		7
Our Subordinated Securities		8
Our Options		8
Our Warrants		9
Our Rights		10
CASH DISTRIBUTION POLICY		12
Distributions of Available Cash		12
Adjustment of Quarterly Distribution Amounts		12
Distributions of Cash Upon Liquidation		12
DESCRIPTION OF OUR PARTNERSHIP AGREEMENT		13
Partnership Purpose		13
Power of Attorney		13
Reimbursements of Our General Partner		13
Issuance of Additional Securities		13
Amendments to Our Partnership Agreement		13
Withdrawal or Removal of Our General Partner		14
Liquidation and Distribution of Proceeds		14


	Page
Change of Management Provisions		15
Limited Call Right		15
Indemnification		15
DESCRIPTION OF DEBT SECURITIES AND GUARANTEES		16
General		16
Indentures		16
Series of Debt Securities		17
Amounts of Issuances		17
Principal Amount, Stated Maturity and Maturity		17
Specific Terms of Debt Securities		18
Governing Law		19
Form of Debt Securities		19
Redemption or Repayment		22
Mergers and Similar Transactions		23
Subordination Provisions		23
Defeasance, Covenant Defeasance and Satisfaction and Discharge		25
No Personal Liability		25
Default, Remedies and Waiver of Default		26
Modifications and Waivers		27
Special Rules for Action by Holders		29
Form, Exchange and Transfer		30
Payments		31
Guarantees		31
Paying Agents		32
Notices		33
Our Relationship With the Trustee		33
Warrants to Purchase Debt Securities		33
MATERIAL INCOME TAX CONSEQUENCES		35
Partnership Status		35
Limited Partner Status		37
Tax Consequences of Unit Ownership		38
Tax Treatment of Operations		42
Disposition of Common Units		43
Uniformity of Units		45
Tax-Exempt Organizations and Other Investors		46
Administrative Matters		47
State, Local, Foreign and Other Tax Consequences		49
INVESTMENT IN GENESIS BY EMPLOYEE BENEFIT PLANS		50
PLAN OF DISTRIBUTION		53
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS		55
LEGAL MATTERS		57
EXPERTS		57
WHERE YOU CAN FIND MORE INFORMATION		58

You should rely only on the information contained in or incorporated by reference into this prospectus supplement, the accompanying base prospectus and any free writing prospectus prepared by or on behalf of us relating to this offering of common units. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with

additional, different or inconsistent information, you should not rely on it. We are offering to sell the common units, and seeking offers to buy the common units, only in jurisdictions where offers and sales are permitted. You should not assume that the information contained in this prospectus supplement, the accompanying base prospectus or any free writing prospectus is accurate as of any date other than the dates shown in these documents or that any information we have incorporated by reference herein is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since such dates.

None of Genesis Energy, L.P., the underwriters or any of their respective representatives is making any representation to you regarding the legality of an investment in our common units by you under applicable laws. You should consult your own legal, tax and business advisors regarding an investment in our common units. Information in this prospectus supplement and the accompanying base prospectus is not legal, tax or business advice to any prospective investor.

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ABOUT THIS PROSPECTUS SUPPLEMENT

This document is in two parts. The first part is this prospectus supplement, which describes the specific terms of this offering of common units. The second part is the accompanying base prospectus, which gives more general information, some of which may not apply to this offering of common units. Generally, when we refer only to the “prospectus,” we are referring to both parts combined. If the information about the common units offering varies between this prospectus supplement and the accompanying base prospectus, you should rely on the information in this prospectus supplement.

Any statement made in this prospectus or in a document incorporated or deemed to be incorporated by reference into this prospectus will be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any other subsequently filed document that is also incorporated by reference into this prospectus modifies or supersedes that statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus. Please read “Where You Can Find More Information.”

SUMMARY

This summary highlights information included or incorporated by reference in this prospectus supplement and the accompanying base prospectus. It does not contain all the information that may be important to you or that you may wish to consider before making an investment decision. You should read carefully the entire prospectus supplement, the accompanying base prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of our business and the terms of this offering, as well as the tax and other considerations that are important to you in making your investment decision. Please read “Risk Factors” beginning on page S-21 of this prospectus supplement, page 2 of the accompanying base prospectus and page 23 of the Annual Report on Form 10-K for the year ended December 31, 2014 for information regarding risks you should consider before investing in our common units.

Unless the context otherwise requires, references in this prospectus supplement to (i) “Genesis Energy, L.P.,” “Genesis,” “we,” “our,” “us” or like terms refer to Genesis Energy, L.P. and its operating subsidiaries; (ii) “our general partner” refer to Genesis Energy, LLC, the general partner of Genesis; (iii) “CO₂” means carbon dioxide and “NaHS,” which is commonly pronounced as “nash,” mean sodium hydrosulfide; (iv) “April 2015 common units offering” refer to our offering of 4.6 million common units that closed on April 10, 2015 for net proceeds of $198.2 million that we used to repay a portion of the borrowings outstanding under our revolving credit facility; (v) the “2018 notes tender offer and redemption” refer to our tender offer for all $350 million aggregate principal amount of the 7.875% senior notes due 2018 and the redemption of all 7.875% senior notes due 2018 that remained outstanding after the completion of such tender offer; and (vi) “May 2015 notes offering” refer to the offering of $400 million aggregate principal amount of 6.000% senior notes due 2023 by Genesis and a subsidiary co-issuer that closed on May 21, 2015 for net proceeds of $392.0 million that we used to fund the 2018 notes tender offer and redemption and repay a portion of the borrowings outstanding under our revolving credit facility. Unless the context otherwise indicates, the information included in this prospectus supplement assumes that the underwriters do not exercise their option to purchase additional common units.

Our Company

We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and in the Gulf of Mexico. Our common units are traded on the NYSE under the ticker symbol “GEL.”

We provide an integrated suite of services to oil producers, refineries, and industrial and commercial enterprises. Our business activities are primarily focused on providing services around and within refinery complexes. Upstream of the refineries, we provide gathering and transportation of crude oil. Within the refineries, we provide services to assist in their sulfur balancing requirements. Downstream of refineries, we provide transportation services as well as market outlets for their finished refined products. We have a diverse portfolio of customers, operations and assets, including pipelines, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and trucks. Substantially all of our revenues are derived from providing services to integrated oil companies, large independent oil and gas or refinery companies, and large industrial and commercial enterprises.

We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly owned subsidiary that owns a non-economic general partner interest in us, has sole responsibility for conducting our business and managing our operations. Our outstanding common units (including our Class B common units) representing limited partner interests constitute all of the economic equity interests in us.

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We manage our businesses through five divisions that constitute our reportable segments — Onshore Pipeline Transportation, Offshore Pipeline Transportation, Refinery Services, Marine Transportation, and Supply and Logistics.

Onshore Pipeline Transportation Segment

Crude Oil Pipelines

We own four onshore crude oil pipeline systems, with approximately 500 miles of pipe located primarily in Alabama, Florida, Louisiana, Mississippi and Texas. The Federal Energy Regulatory Commission, or FERC, regulates the rates charged by three of our onshore systems to their customers. The rates for the other onshore pipeline are regulated by the Railroad Commission of Texas. Our onshore pipelines generate cash flows from fees charged to customers.

Each of our onshore pipelines has significant available capacity to accommodate potential future growth in volumes.

CO₂Pipelines

We own two CO₂ pipelines with approximately 270 miles of pipe. We have leased our NEJD System, comprised of 183 miles of pipe in North East Jackson Dome, Mississippi, to an affiliate of a large, independent oil company through 2028. We receive a fixed quarterly payment under the NEJD arrangement. That company also has the exclusive right to use our Free State pipeline, comprised of 86 miles of pipe, pursuant to a transportation agreement that expires in 2028. Payments on the Free State pipeline are subject to an “incentive” tariff which provides that the average rate per mcf that we charge during any month decreases as our aggregate throughput for that month increases above specified thresholds.

Offshore Pipeline Transportation Segment

We own interests in various offshore crude oil pipeline systems, with approximately 1,200 miles of pipe and an aggregate design capacity of approximately 1,200 MBbls per day, located offshore in the Gulf of Mexico, a producing region representing approximately 15% of the crude oil production in the United States in 2014. For example, we own a 28% interest in the Poseidon pipeline system, or Poseidon, and a 50% interest in the Cameron Highway pipeline system, or CHOPS, which is one of the largest crude oil pipelines (in terms of both length and design capacity) located in the Gulf of Mexico. We also own a 50% interest in Southeast Keathley Canyon Pipeline Company, LLC, or SEKCO, which is a deepwater oil pipeline servicing the Lucius field in the southern Keathley Canyon area of the Gulf of Mexico that became operational in 2014. Our offshore pipelines generate cash flows from fees charged to customers or substantially similar arrangements that otherwise limits our direct exposure to changes in commodity prices.

Each of our offshore pipelines currently has significant available capacity to accommodate future growth in the fields from which the production is dedicated to that pipeline as well as to transport volumes from non-dedicated fields both currently in production and to be developed in the future.

Refinery Services Segment

We primarily (i) provide services to ten refining operations located primarily in Texas, Louisiana, Arkansas, Oklahoma and Utah; (ii) operate significant storage and transportation assets in relation to those services; and (iii) sell NaHS and caustic soda to large industrial and commercial companies. Our refinery services primarily involve processing refiners’ high sulfur (or “sour”) gas streams to remove the sulfur. Our refinery services footprint also includes terminals, and we utilize railcars, ships, barges and trucks to transport product. Our refinery services contracts are typically long-term in nature and have an average remaining term of three years. NaHS is a by-product derived from our refinery services process, and it

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constitutes the sole consideration we receive for these services. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HollyFrontier and Ergon. We sell our NaHS to customers in a variety of industries, with the largest customers involved in mining of base metals, primarily copper and molybdenum, and the production of pulp and paper. We believe we are one of the largest marketers of NaHS in North and South America.

Marine Transportation Segment

We own a fleet of 71 barges (62 inland and 9 offshore) with a combined transportation capacity of 2.6 million barrels and 36 push/tow boats (27 inland and 9 offshore). Our marine transportation segment is a provider of transportation services by tank barge primarily for refined petroleum products, including heavy fuel oil and asphalt, as well as crude oil.

In November 2014, we also acquired from Mid Ocean Tanker Company, LLC, the M/T American Phoenix, an ocean going tanker with 330,000 barrels of cargo capacity. The M/T American Phoenix is currently transporting refined products.

We are a provider of transportation services for our customers and, in almost all cases, do not assume ownership of the products that we transport. Most of our marine transportation services are conducted under term contracts, some of which have renewal options for customers with whom we have traditionally had long-standing relationships. All of our vessels operate under the United States flag and are qualified for domestic trade under the Jones Act.

Supply and Logistics Segment

Our supply and logistics segment is focused on utilizing our knowledge of the crude oil and petroleum markets to provide oil and gas producers, refineries and other customers with a full suite of services. Our supply and logistics segment owns or leases trucks, terminals, gathering pipelines, railcars, and rail loading and unloading facilities. It uses those assets, together with other modes of transportation owned by third parties and us, to service its customers and for its own account. We have access to a suite of more than 300 trucks, 400 trailers, 562 railcars, and terminals and tankage with 2.9 million barrels of storage capacity in multiple locations along the Gulf Coast as well as capacity associated with our three common carrier crude oil pipelines. Our crude-by-rail operations consist of a total of six facilities, either in operation or under construction, designed to load and/or unload crude oil. The two facilities located in Texas and Wyoming were designed primarily to load crude oil produced locally onto railcars for further transportation to refining markets. The four other facilities (two in Louisiana, one in Mississippi and one in Florida) were designed primarily to unload crude oil from railcars into pipelines, or onto barges, for delivery to refinery customers. Usually, our supply and logistics segment experiences limited commodity price risk because it utilizes back-to-back purchases and sales, matching sale and purchase volumes on a monthly basis. Unsold volumes are hedged with NYMEX derivatives to offset the remaining price risk.

Our Objectives and Strategies

Our primary business objectives are to generate stable cash flows that allow us to make quarterly cash distributions to our unitholders and to increase those distributions over time. We plan to achieve those objectives by executing the following business and financial strategies.

Business Strategy

Our primary business strategy is to provide an integrated suite of services to oil and gas producers, refineries and other customers. Successfully executing this strategy should enable us to generate and grow sustainable cash flows. Onshore, we focus primarily on customers further downstream in the energy value chain, like refiners (as opposed to producers). For example, refiners are the shippers of over 85% of the volumes transported on our onshore crude pipelines, and refiners contract for more than 90% of the use of

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our inland barges, which primarily are used to transport intermediate refined products (not crude oil) between refining complexes. Our crude oil pipelines in the Gulf of Mexico represent the single largest departure from our “refinery-centric” customer strategy. The shippers on those pipelines are mostly integrated and large independent energy companies who have developed, and continue to explore for, numerous large-reservoir, long-lived crude oil properties whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Those large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in this lower commodity price environment.

We intend to develop our business by:

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Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated footprint;

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Optimizing our existing assets and creating synergies through additional commercial and operating advancement;

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Leveraging customer relationships across business segments;

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Attracting new customers and expanding our scope of services offered to existing customers;

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Expanding the geographic reach of our refinery services, onshore and offshore pipeline systems, marine transportation and supply and logistics businesses;

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Economically expanding our pipeline and terminal operations;

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Evaluating internal and third-party growth opportunities (including asset and business acquisitions) that leverage our core competencies and strengths and further integrate our businesses; and

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Focusing on health, safety and environmental stewardship.

We regularly consider and enter into discussions regarding potential acquisitions and are currently contemplating potential acquisitions. On July 16, 2015, we entered into a purchase and sale agreement with Enterprise Products Operating LLC, or EPO, pursuant to which we will acquire the offshore pipelines and services business of EPO and its affiliates for approximately $1.5 billion. Please read “—Pending Acquisition of Enterprise Offshore Pipelines and Services Business” for additional information. While there are currently no unannounced purchase agreements for the acquisition of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.

Financial Strategy

We believe that preserving financial flexibility is an important factor in our overall strategy and success. Over the long-term, we intend to:

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Increase the relative contribution of recurring and throughput-based revenues, emphasizing longer-term contractual arrangements;

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Prudently manage our limited commodity price risks;

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Maintain a sound, disciplined capital structure; and

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Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances.

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Our Competitive Strengths

We believe we are well-positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths:

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We have limited commodity price risk exposure. The volumes of crude oil, refined products or intermediate feedstocks we purchase are either subject to back-to-back sales contracts or are hedged with NYMEX derivatives to limit our exposure to movements in the price of the commodity, although we cannot completely eliminate commodity price exposure. Our risk management policy requires that we monitor the effectiveness of the hedges to maintain a value at risk of such hedged inventory that does not exceed $2.5 million. In addition, our service contracts with refiners allow us to adjust the rates we charge for processing to maintain a balance between NaHS supply and demand.

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Our businesses encompass a balanced, diversified portfolio of customers, operations and assets. We operate five business segments and own and operate assets that enable us to provide a number of services to oil producers, refinery owners, and industrial and commercial enterprises that use NaHS and caustic soda. Our business lines complement each other by allowing us to offer an integrated suite of services to common customers across segments. Our businesses are primarily focused on providing services around and within refinery complexes. We are not dependent upon any one customer or principal location for our revenues.

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Our onshore and offshore pipeline transportation and related assets are strategically located. Our pipelines are critical to the ongoing operations of our producer and refiner customers. In addition, a majority of our terminals are located in areas that can be accessed by truck, rail or barge.

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We believe we are one of the largest marketers of NaHS in North and South America. We believe the scale of our well-established refinery services operations as well as our integrated suite of assets provides us with a unique cost advantage over some of our existing and potential competitors.

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Our supply and logistics business is operationally flexible. Our portfolio of trucks, railcars, barges and terminals affords us flexibility within our existing regional footprint and provides us the capability to enter new markets and expand our customer relationships.

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Our marine transportation assets provide waterborne transportation throughout North America. Our fleet of barges and boats provide service to both inland and offshore customers within a large North American geographic footprint. There are a limited number of Jones Act qualified vessels participating in United States coastwise trade. All of our vessels operate under the United States flag and are qualified for United States coastwise trade under the Jones Act.

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Our businesses provide consistent consolidated financial performance. Our consistent and improving financial performance, combined with our conservative capital structure, has allowed us to increase our distribution for 40 consecutive quarters as of our most recent distribution declaration. During this period, 35 of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year.

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We are financially flexible and have significant liquidity. As of March 31, 2015, on an adjusted pro forma basis after giving effect to the application of the net proceeds from the April 2015 common units offering and May 2015 notes offering, we had $573.3 million available under our $1.0 billion revolving credit facility, including up to $101.7 million available under the $150 million petroleum products inventory loan sublimit, and $88.8 million available for letters of credit. Our inventory borrowing base was $48.3 million at March 31, 2015. On July 16, 2015, we received commitments to increase the committed amount under our revolving credit facility from $1.0 billion to $1.5 billion effective as of the closing of the Enterprise Offshore Business Acquisition.

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Our expertise and reputation for high performance standards and quality enable us to provide refiners with economic and proven services. Our extensive understanding of the sulfur removal process and crude oil refining can provide us with an advantage when evaluating new opportunities and/or markets.

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We have an experienced, knowledgeable and motivated executive management team with a proven track record. Our executive management team has an average of more than 25 years of experience in the midstream sector. Its members have worked in leadership roles at a number of large, successful public companies, including other publicly traded partnerships. Through their equity interest in us, our executive management team is incentivized to create value by increasing cash flows.

Pending Acquisition of Enterprise Offshore Pipelines and Services Business

Purchase and Sale Agreement

On July 16, 2015, we entered into a purchase and sale agreement with EPO pursuant to which we will acquire the offshore pipelines and services business of EPO and its affiliates on the terms and subject to the conditions set forth in the purchase and sale agreement for approximately $1.5 billion in cash. We refer to the business that we will acquire as the Enterprise Offshore Business and the acquisition of the Enterprise Offshore Business as the Enterprise Offshore Business Acquisition.

The purchase and sale agreement contains customary representations and warranties, covenants and agreements. The purchase and sale agreement also contains customary closing conditions and termination rights for both parties. All of these closing conditions, other than those that, by their nature, are to be satisfied at the closing, have been satisfied or waived. We expect to close the Enterprise Offshore Business Acquisition in the third quarter of 2015.

We cannot assure you that the Enterprise Offshore Business Acquisition will be completed within our anticipated time frame or at all or that we will achieve our strategic and financial objectives related to the Enterprise Offshore Business Acquisition. The completion of this offering is not contingent upon the completion of the Enterprise Offshore Business Acquisition and the completion of the Enterprise Offshore Business Acquisition is not contingent upon the completion of this offering, the concurrent notes offering or any other financing. If you decide to purchase our common units in this offering, you should be willing to do so whether or not we complete the Enterprise Offshore Business Acquisition. Investors in our common units should not place undue reliance on the pro forma financial data included in this prospectus supplement because this offering is not contingent upon any of the transactions reflected in the adjustments included in that data.

The Enterprise Offshore Business

The Enterprise Offshore Business, which serves some of the most active drilling and development regions in the United States (including deepwater production fields in the Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama), will be complementary to, and will substantially expand, our existing offshore pipelines segment, which is primarily comprised of our interests in three oil pipelines—Poseidon (28%), SEKCO (50%), and CHOPS (50%). The Enterprise Offshore Business includes approximately 2,350 miles of offshore crude oil and natural gas pipelines and six offshore hub platforms, including an additional 36% interest in Poseidon and all the remaining interest in SEKCO and CHOPS.

The Enterprise Offshore Business’ Gulf of Mexico pipelines provide for the gathering and transportation of crude oil or natural gas from offshore production fields to interconnecting offshore or onshore pipelines or processing facilities. The Enterprise Offshore Business’ offshore hub platforms are typically used to interconnect the offshore pipeline network; provide an efficient means to perform pipeline

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maintenance; and locate pumping, compression, separation and production handling equipment and similar assets. In addition to the offshore hub platforms, the Enterprise Offshore Business owns 15 pipeline junction and service platforms.

Rationale for Enterprise Offshore Business Acquisition

We believe the Enterprise Offshore Business Acquisition will facilitate our ability to grow our cash flow and distribution per unit, enhance our credit quality over time, expand our portfolio of strategic assets, and increase our opportunity to experience organic growth in the future. Our rationale for the Enterprise Offshore Business Acquisition includes the following:

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Meaningfully expands our size and credit metrics over the longer-term, which should help accelerate an increase in our credit ratings in the future. After consummation and integration of the Enterprise Offshore Business Acquisition, we expect to generate quarterly Adjusted EBITDA of over $140 million for the three months ending December 31, 2015 (or $560 million annualized) and quarterly net income of over $45 million for the three months ending December 31, 2015 (or $180 million annualized). The increase from historical pro forma Adjusted EBITDA and net income for the year ended December 31, 2014 is primarily attributable to (i) a full year of cash flows from fee-based contracts for SEKCO, (ii) a full year of cash flows from long-term contracts for the M/T American Phoenix and our expanded inland marine barge transportation fleet, and (iii) increased volumes transported on our offshore pipelines, in particular Poseidon. Please see “–Summary Historical and Pro Forma Consolidated Financial Information and Other Data of Genesis Energy, L.P.–Reconciliation of Estimated Adjusted EBITDA to Estimated Net Income” for a reconciliation of estimated Adjusted EBITDA to estimated net income and information regarding the components of these estimates and the speculative nature of these estimates.

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Immediately accretive to our cash available for distribution. We believe the Enterprise Offshore Business Acquisition will be immediately accretive to our cash available for distribution per common unit.

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Generates substantial, relatively stable cash flows under long term, fee-based contracts, with no direct commodity price exposure. Like the other assets in our offshore pipeline transportation segment, a substantial majority of the cash flow generated by the Enterprise Offshore Business is under long-term (often, life-of-lease) service agreements that provide fixed fee (or substantially similar) arrangements for each per barrel of oil and per thousand cubic feet of natural gas handled.

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Substantially enlarges our footprint of strategic infrastructure in one of the most prolific producing regions in the United States. The Enterprise Offshore Business Acquisition substantially enlarges our footprint of strategic infrastructure in the Gulf of Mexico, a producing region representing approximately 15% of the crude oil production in the United States in 2014. Even given today’s lower commodity price environment, the number of mobile offshore drilling units working in the Gulf of Mexico has remained relatively constant during the last twelve months (42 units as of June 30, 2015 versus 41 units as of June 30, 2014), while the number of onshore drilling rigs has declined significantly, from 1,800 rigs a year ago to 824 rigs today). Among other things, the Enterprise Offshore Business Acquisition increases our interest in three significant crude oil pipelines—Poseidon (to 64% from 28%), SEKCO (to 100% from 50%) and CHOPS (to 100% from 50%), which is one of the largest crude oil pipelines in the Gulf of Mexico—and adds six oil pipeline systems and nine natural gas pipeline systems to our portfolio.

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Increases our opportunity to experience organic growth in the future. Due to the larger footprint provided by the Enterprise Offshore Business Acquisition, we expect to develop more organic growth projects in our offshore pipeline segment, given our expectation that producers in the Gulf of Mexico will continue to develop capital intensive, large-reservoir properties throughout the Gulf of Mexico, even in today’s lower commodity price environment.

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Facilitates our ability to realize our primary financial goals. The size, characteristics and financial contributions of the Enterprise Offshore Business Acquisition should facilitate our ability to realize our primary financial goals over the next five years— expected low, double-digit growth in our distributions per unit while gradually increasing our coverage ratio and ultimately achieving an investment grade leverage ratio.

Financing for Enterprise Offshore Business Acquisition

We expect to finance the Enterprise Offshore Business Acquisition with the net proceeds from this offering and our concurrent senior notes offering (as described below) and borrowings under our revolving credit facility.

Concurrent Notes Offering

Concurrently with this offering, we and one of our subsidiaries as co-issuer are offering $750 million aggregate principal amount of senior notes due 2022.

This prospectus supplement shall not be deemed an offer to sell or a solicitation of an offer to buy any of the senior notes. The offering of common units pursuant to this prospectus is not contingent upon the closing of the senior notes offering or the closing of the Enterprise Offshore Business Acquisition and the concurrent offering of senior notes is not contingent upon the closing of this offering of common units. If you decide to purchase our common units in this offering, you should be willing to do so whether or not the concurrent senior notes offering closes.

If the purchase and sale agreement for the Enterprise Offshore Business Acquisition is terminated at any time prior to the closing of the acquisition or if the closing of the acquisition does not otherwise occur on or prior to December 31, 2015, we will redeem all of the notes at a redemption price equal to 100% of the aggregate issue price of the notes plus accrued and unpaid interest to, but not including, the redemption date.

Expanded Revolving Credit Facility

On July 16, 2015, we received commitments to increase the committed amount under our revolving credit facility from $1.0 billion to $1.5 billion effective as of the closing of the Enterprise Offshore Business Acquisition.

Bridge Facility Commitment

We also entered into a commitment letter with Wells Fargo Bank, N.A., WF Investment Holdings, LLC, Wells Fargo Securities, LLC, Bank of America, N.A., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Bank of Montreal, and BMO Capital Markets Corp. for alternative financing if this offering and the concurrent offering of senior notes do not close or do not close in full. Pursuant to the commitment letter, we have received commitments for senior unsecured loans in an aggregate principal amount of up to $1.0 billion under a bridge facility. The bridge facility will only be drawn if and to the extent the net proceeds from this offering and the concurrent offering of senior notes received at or prior to the closing of the Enterprise Offshore Business Acquisition are insufficient, together with available borrowing capacity under our expanded revolving credit facility, to close the Enterprise Offshore Business Acquisition.

Recent Events

40 Consecutive Distribution Rate Increases

We have increased our quarterly distribution rate for 40 consecutive quarters. During this period, 35 of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. Our board of directors has declared a cash distribution of $0.625 per common unit for the quarter ended

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June 30, 2015 to common unitholders of record on July 31, 2015, an approximate 2.5% increase from the distribution in the prior quarter, and an increase of 10.6% from the distribution paid for the quarter ended June 30, 2014. As in the past, future increases (if any) in our quarterly distribution rate will depend on our ability to execute critical components of our business strategy.

Acquisition of the M/T American Phoenix

On November 13, 2014, we completed the acquisition of the M/T American Phoenix from Mid Ocean Tanker Company for $157 million, which became part of our offshore marine transportation business. The M/T American Phoenix is a modern double-hulled, Jones Act qualified tanker with 330,000 barrels of cargo capacity that was placed into service during 2012. That acquisition complements and further integrates our existing operations, including our inland barge business and our offshore tank barge and tug business.

Inland Marine Barge Transportation Expansion

We ordered 20 new-build barges and 14 new-build push boats for our inland marine barge transportation fleet. We have accepted delivery of eight of those barges and five of those push boats as of June 2015. We expect to take delivery of the remaining vessels periodically into 2017.

ExxonMobil Baton Rouge Project

We are improving existing assets and developing new infrastructure in Louisiana, including connecting to Exxon Mobil Corporation’s Baton Rouge refinery, one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. Our investment includes improving our existing terminal at Port Hudson, Louisiana, and building a new crude oil unit train unload facility at Scenic Station as well as constructing a new 17-mile 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the ExxonMobil Anchorage Tank Farm. The Port Hudson upgrades and new crude oil pipeline were completed in the first quarter of 2014, and Scenic Station became operational in July 2014.

Baton Rouge Terminal

We are constructing a new crude oil, intermediates and refined products import/export terminal in Baton Rouge that will be located near the Port of Greater Baton Rouge and will be pipeline-connected to the port’s existing deepwater docks on the Mississippi River. We will initially construct approximately 1.1 million barrels of tankage for the storage of crude oil, intermediates and/or refined products with the capability to expand to provide additional terminaling services to our customers. In addition, we plan to construct a new pipeline from the terminal that will allow for deliveries to existing Exxon Mobil facilities in the area, as well as connect our previously constructed 17 mile line to the terminal allowing for receipts from the Scenic Station Rail Facility. Shippers to Scenic Station will have access to both the local Baton Rouge refining market, as well as the ability to access other attractive refining markets via our Baton Rouge Terminal. The Baton Rouge Terminal is expected to be operational by the end of the third quarter of 2015.

Deepwater Gulf of Mexico Pipeline Joint Venture

In June 2014, SEKCO, our 50/50 joint venture with Enterprise Products Partners, L.P., or Enterprise Products, completed its deepwater oil pipeline serving the Lucius oil and gas field in the southern Keathley Canyon area of the Gulf of Mexico. SEKCO has crude oil transportation agreements with six Gulf of Mexico producers, including Anadarko U.S. Offshore Corporation, Apache Deepwater Development LLC, Exxon Mobil Corporation, Eni Petroleum US LLC, Petrobras America and Plains Offshore Operations, Inc. Those producers have dedicated their production from Lucius to the pipeline for the life of the reserves. We expect

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the SEKCO pipeline to also provide capacity for additional projects in the deepwater Gulf of Mexico in the future. Enterprise Products served as construction manager and is the operator of the SEKCO pipeline. SEKCO’s customers commenced paying fees to SEKCO upon completion of its pipeline in 2014 and commenced crude oil deliveries to the SEKCO pipeline in the first quarter of 2015.

The 149-mile, 18-inch diameter pipeline, designed to have a 115,000 barrel per day capacity, connects the Lucius-truss spar floating production platform to an existing junction platform at South Marsh Island that is part of the Poseidon pipeline system, in which we own a 28% interest. We will acquire the other 50% of SEKCO in the Enterprise Offshore Business Acquisition.

Rail Projects

Walnut Hill — In 2013, we completed construction on the second phase of our crude-by-rail unloading terminal at Walnut Hill, Florida, which includes a 100,000 barrel storage tank, related equipment and connections to our Jay System. In April 2014, we completed construction of an additional 110,000 barrel storage tank at our Walnut Hill, Florida crude-by-rail terminal, which will allow us to handle increased rail and pipeline demand. That terminal is connected to our Jay System and now includes 210,000 Barrels of capacity.

Wink — In April 2014, we completed construction on the second phase of our crude oil rail loading facility in Wink, Texas, which allows us to more efficiently load full unit trains. That facility was designed to move crude oil from West Texas to other markets and gives us the capability to load Genesis and third party railcars.

Natchez — During the first quarter of 2014, we completed construction on the second phase of our crude oil rail unloading/loading facility at our existing terminal located in Natchez, Mississippi, which provides an additional 60 railcar spots and additional heated tanks. That facility is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets via the Mississippi River. This facility has the capability to heat and unload bitumen/dilbit, load trucks, blend crude oil and load barges for distribution to refineries.

Raceland — The Raceland Rail Facility, a new crude oil unit train unloading facility capable of unloading up to two unit trains per day, which is located in Raceland, Louisiana, will be connected to existing midstream infrastructure that will provide direct pipeline access to the Louisiana refining markets and is expected to be operational in the second half of 2015.

Financial Results for the Second Quarter of 2015 (unaudited)

The following amounts are estimates of certain key financial results that we expect for the second quarter of 2015:

•

Adjusted EBITDA of between $87.0 million and $87.5 million;

•

Available Cash before Reserves of between $68.5 million and $69.0 million; and

•

Net Income of between $11.3 million and $11.8 million.

Although full results for the second quarter of 2015 are not yet available, based upon information available to us and except as otherwise described in this prospectus supplement, we are not aware and do not anticipate that our results for the second quarter will be adversely affected, in the aggregate, by material or unusual events, and we believe that, during the second quarter we did not incur material additional borrowings or other liabilities, contingent or otherwise, or default under our debt covenants. Nevertheless, our actual results for the second quarter of 2015 may differ from these expectations and from the estimates disclosed above, and such differences could be material. Our expected results for this interim period are not indicative of the results that should be expected for the full fiscal year.

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Neither our independent registered public accountants nor any other independent registered public accountants have compiled, examined or performed any procedures with respect to the prospective financial information contained herein or expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information.

Adjusted EBITDA is a non-GAAP financial measure and should not be construed as an alternative to, or more meaningful than, GAAP financial information. Please see “—Summary Historical and Pro Forma Consolidated Financial Information and Other Data of Genesis Energy, L.P.—Non-GAAP Financial Measures” for additional qualifications regarding the use of Adjusted EBITDA and Available Cash before Reserves. The following table reconciles our range of estimated Adjusted EBITDA and Available Cash before Reserves to estimated Net Income for the second quarter of 2015:


	Three months ended June 30, 2015
	(Estimated data; in millions)
Adjusted EBITDA		between	$	87.0		and	$	87.5
Loss on redemption of senior notes		between		(17.5	)	and		(17.5	)
Depreciation and amortization		between		(28.2	)	and		(28.2	)
Interest expense, net		between		(18.0	)	and		(18.0	)
Other items		between		(12.0	)	and		(12.0	)

Net income		between	$	11.3		and	$	11.8


	Three months ended June 30, 2015
	(Estimated data; in millions)
Available cash before reserves		between	$	68.5		and	$	69.0
Loss on redemption of senior notes		between		(17.5	)	and		(17.5	)
Depreciation and amortization		between		(28.2	)	and		(28.2	)
Other items		between		(11.5	)	and		(11.5	)

Net income		between	$	11.3		and	$	11.8

Our Offices

Our principal executive offices are located at 919 Milam, Suite 2100, Houston, Texas 77002, and the phone number at this address is (713) 860-2500.

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Ownership Structure

Below is a chart depicting our ownership structure after giving effect to this offering but before any exercise of the underwriters’ option to purchase additional common units.

LOGO

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The Offering

Common Units Offered by Us

9,000,000 common units (10,350,000 common units if the underwriters exercise their option to purchase additional common units in full).

Common Units Outstanding Before this Offering

99,589,221 common units.

Common Units Outstanding After this Offering

108,589,221 common units (109,939,221 common units if the underwriters exercise their option to purchase additional common units in full).

Use of Proceeds

We expect to receive net proceeds from this offering of approximately $ million, after payment of the underwriters’ discounts and commissions and estimated offering expenses. We intend to use the net proceeds, including any net proceeds from the underwriters’ exercise of their option to purchase additional common units, to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition and any remaining net proceeds for general partnership purposes, including funding acquisitions (including organic growth projects) or repaying a portion of the borrowings outstanding under our revolving credit facility. If the Enterprise Offshore Business Acquisition does not close, we intend to use all of the net proceeds, including any net proceeds from the underwriters’ exercise of their option to purchase additional common units, for general partnership purposes, including funding acquisitions (including organic growth projects) or repaying a portion of the borrowings outstanding under our revolving credit facility.

Cash Distributions

Within approximately 45 days after the end of each quarter, we will distribute all available cash to the unitholders of record on the applicable record date. There is no guarantee that we will pay a distribution on our units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or if an event of default then exists, under our revolving credit facility. Please read “Cash Distribution Policy” in the accompanying base prospectus.

Our board of directors has declared a cash distribution of $0.625 per common unit for the quarter ended June 30, 2015 which will be paid on August 14, 2015 to common unitholders at the close of business on July 31, 2015. This distribution represents an approximate 2.5% increase per unit from the distribution in the prior quarter, and an increase of approximately 10.6% from the distribution in August 2014. We have increased our quarterly distribution rate for 40 consecutive quarters.

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Estimated Ratio of Taxable Income to Distributions

We estimate that if you own the common units that you purchase in this offering through the record date for the distribution with respect to the final calendar quarter of 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. Please read “Material Tax Considerations” in this prospectus supplement for the basis of this estimate.

Certain Relationships

As described in “Use of Proceeds,” some of the net proceeds of the offering of common units by us may be used to repay outstanding borrowings under our revolving credit facility. Because Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., RBC Capital Markets, LLC and BMO Capital Markets Corp. or their respective affiliates are lenders under our revolving credit facility, certain of the underwriters or their affiliates may receive more than 5% of the proceeds of this offering (not including underwriting discounts and commissions). Nonetheless, in accordance with the Financial Industry Regulatory Authority Rule 5121, the appointment of a qualified independent underwriter is not necessary in connection with this offering because the common units offered by us are interests in a direct participation program. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

New York Stock Exchange Symbol

GEL

Material Tax Consequences

For a discussion of 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 Tax Considerations” in this prospectus supplement and “Material Income Tax Consequences” in the accompanying base prospectus.

Risk Factors

You should read “Risk Factors” in this prospectus supplement, the accompanying base prospectus and found in the documents incorporated herein by reference, as well as the other cautionary statements throughout this prospectus supplement, to ensure you understand the risks associated with an investment in our common units.

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Summary Historical and Pro Forma Consolidated Financial Information and Other Data of Genesis Energy, L.P.

Our summary historical financial data were derived from our historical financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2014 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 incorporated by reference into this prospectus supplement. The summary historical financial data do not purport to project our results of operations or financial position for any future period or as of any date and are not necessarily indicative of financial results to be achieved in future periods. You should read the summary historical financial data together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 incorporated by reference into this prospectus supplement. See “Where You Can Find More Information.”

Our historical consolidated financial statements as of and for the years ended December 31, 2012, 2013 and 2014 have been audited. Our historical consolidated financial statements as of and for the three months ended March 31, 2014 and 2015 are unaudited. We believe they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Results of operations for any interim period are not necessarily indicative of the results of operations for our entire fiscal year.

Our summary unaudited pro forma condensed combined statement of operations data for the three months ended March 31, 2015 and for the year ended December 31, 2014 give effect on a pro forma basis to the following transactions as if each had occurred on January 1, 2014 and our summary unaudited pro forma condensed combined balance sheet data as of March 31, 2015 gives effect on a pro forma basis to the following transactions as if each had occurred on March 31, 2015:

(1)

the sale and issuance of 9,000,000 common units pursuant to this offering at an assumed public offering price of $46.49 per common unit, which was the closing price of our common units on the NYSE on July 15, 2015, and the application of the estimated $403.4 million net proceeds therefrom to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition;

(2)	the sale and issuance of $750,000,000 aggregate principal amount of senior notes pursuant to the concurrent senior notes offering and the application of the estimated $736.9 million net proceeds therefrom to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition;

(3)	estimated borrowings of $395.8 million under our revolving credit facility to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition and to pay estimated offering and transaction expenses; and

(4)

the closing of the Enterprise Offshore Business Acquisition, including (a) the effects of adjustments to reflect the ownership interests in Cameron Highway Oil Pipeline Company and Southeast Keathley Canyon Pipeline Company, L.L.C. that we held prior to the closing of the Enterprise Offshore Business Acquisition at fair value based on the purchase price allocated to ownership interests in these entities that we are acquiring pursuant to the Enterprise Offshore Business Acquisition and (b) the reflection of the ownership interests in Cameron Highway Oil Pipeline Company and Southeast Keathley Canyon Pipeline Company, L.L.C. that both we and the Enterprise Offshore Business held prior to the closing of the Enterprise Offshore Business Acquisition as consolidated subsidiaries rather than as equity investments after the closing of the Enterprise Offshore Business Acquisition.

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The financial data set forth below has been presented for informational purposes only and is not necessarily indicative of what our results of operations or financial position actually would have been had the transactions above occurred on the dates indicated. The unaudited pro forma condensed combined financial data should be read in conjunction with “Unaudited Pro Forma Condensed Combined Financial Data” included elsewhere in this prospectus supplement. In addition, the unaudited pro forma combined financial data was based on and should be read in conjunction with our historical consolidated financial statements and accompanying notes incorporated by reference in this prospectus supplement and the Enterprise Offshore Business historical financial statements and accompanying notes included elsewhere in this prospectus supplement. See “Where You Can Find More Information.”


	Pro Forma Three Months Ended March 31,		Historical Three Months Ended March 31,				Pro Forma Year Ended December 31,		Historical Year Ended December 31,
	2015		2015		2014		2014		2014(1)		2013(1)		2012(1)
Income Statement Data (in millions except per Common Unit amounts):
Revenues:
Onshore pipeline transportation	$	19.0	$	19.0	$	20.0	$	83.2	$	83.2	$	82.6	$	70.8
Offshore pipeline transportation		78.5		0.8		0.9		293.1		3.3		3.9		5.5
Refinery services		46.1		46.1		54.2		207.4		207.4		206.0		196.0
Marine transportation		57.4		57.4		56.3		229.3		229.3		152.5		118.2
Supply and logistics		403.5		403.5		888.3		3,323.0		3,323.0		3,689.8		2,976.9
Total revenue	$	604.5	$	526.8	$	1,019.7	$	4,136.0	$	3,846.2	$	4,134.8	$	3,367.4
Equity in earnings of equity investees	$	13.2	$	15.5	$	7.8	$	30.8	$	43.1	$	22.7	$	14.3
Income from continuing operations after income taxes	$	35.8	$	20.2	$	29.8	$	150.3	$	106.2	$	84.0	$	97.3
Income from continuing operations after income taxes attributable to Genesis Energy, L.P.	$	35.4	$	20.2	$	29.8	$	147.8	$	106.2	$	84.0	$	97.3
Income from continuing operations after income taxes attributable to Genesis Energy, L.P. per Common Unit	$	0.34	$	0.21	$	0.34	$	1.49	$	1.18	$	1.00	$	1.24
Cash distributions declared per Common Unit	$	0.595	$	0.595	$	0.535	$	2.2300	$	2.2300	$	2.0150	$	1.8225

Balance Sheet Data (at end of period) (in millions):
Current assets	$	352.4	$	307.9	$	454.3			$	355.4	$	535.2	$	404.0
Total assets	$	5,282.5	$	3,272.1	$	2,857.6			$	3,230.4	$	2,862.2	$	2,109.7
Long-term liabilities	$	3,030.8	$	1,736.7	$	1,376.1			$	1,638.0	$	1,317.9	$	880.5
Total partners’ capital	$	1,878.8	$	1,192.9	$	1,080.1			$	1,229.2	$	1,097.7	$	916.5

Other Data:
Volumes — continuing operations:
Onshore crude oil pipeline (barrels per day)		122,624		122,624		105,239		116,225		116,225		104,026		92,897
Offshore crude oil pipeline (barrels per day)(2)		521,375		181,375		175,246		500,570		170,570		151,618		133,194
Offshore natural gas pipeline (MBtus per day)(2)		618,916		—		—		626,583		—		—		—
CO₂ pipeline (Mcf per day)		190,507		190,507		191,593		173,770		173,770		190,274		186,479
NaHS sales (DST)		32,430		32,430		40,902		150,038		150,038		147,297		142,712
NaOH sales (DST)		21,186		21,186		24,033		94,693		94,693		87,463		77,492
Crude oil and petroleum products sales (barrels per day)		94,193		94,193		100,856		99,139		99,139		99,651		79,174

(1)	Our operating results and financial position have been affected by acquisitions. For additional information regarding our acquisitions and divestitures during 2014, 2013 and 2012, see Note 3 to our consolidated financial statements incorporated by reference into this prospectus supplement.

(2)	Includes volumes attributable to our net ownership interest for equity method investees.

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Reconciliation of Estimated Adjusted EBITDA to Estimated Net Income

The following table reconciles our estimated Adjusted EBITDA to estimated Net Income for the three months ending December 31, 2015 and on an estimated annualized basis:


	Three Months Ending December 31, 2015			Annualized Estimated Fourth Quarter 2015
Estimated Adjusted EBITDA	$	140.0		$	560.0
Adjustments to Estimated Adjusted EBITDA
Interest Expense, net		(35.0	)		(140.0	)
Depreciation, Amortization and Accretion		(45.3	)		(181.2	)
Net Income Effects of Equity Method Investees Not Included in Estimated Adjusted EBITDA		(7.8	)		(31.2	)
Other Items, net		(2.4	)		(9.6	)

Estimated Net Income	$	49.5		$	198.0

The following table sets forth the estimated components of the estimated Adjusted EBITDA included in the table above:


	Genesis		Enterprise Offshore Business			Combined
Year Ended December 31, 2014
Operating income	$	132.6	$	4.3		$	136.9
Depreciation and amortization		90.9		88.6			179.5
Actual equity distributions		75.6		83.5			159.1
Other		2.0		(1.2	)		0.8

Adjusted EBITDA	$	301.1	$	175.2		$	476.3

Year Ending December 31, 2015
SEKCO/Poseidon minimum bill revenue (1)	$	21.2	$	24.5		$	45.7
Growth projects effect on Estimated Adjusted EBITDA (2)		38.0					38.0

2015 Estimated Adjusted EBITDA	$	360.3	$	199.7		$	560.0

(1)	Represents two incremental quarters of minimum bill tariff revenue for SEKCO and Poseidon not included in our results for the year ended December 31, 2014 since they became operational on July 1, 2014.

(2)	Principally inclusive of incremental Estimated Adjusted EBITDA from marine assets (M/T American Phoenix acquisition and additional inland marine barges) and additional growth in Genesis offshore pipeline assets.

Management’s estimates are based upon a number of assumptions. While these estimates are presented with numerical specificity and considered reasonable, they are inherently subject to significant business, economic and competitive uncertainties. Please see “Risk Factors” in this prospectus supplement and in the accompanying base prospectus for additional information regarding the risks and uncertainties that affect our business. These estimated should also be should be read in conjunction with “Information Regarding Forward—Looking Statements” in this prospectus supplement and the accompanying base prospectus.

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The estimates are necessarily speculative in nature, and actual results could differ materially, particularly if actual events differ from one or more of our key assumptions. Our key assumptions include:

•

our expectation that there will be no change in competitive dynamics;

•

our expectation of a stable cost and operating environment;

•

our expectation that our integration of the Enterprise Offshore Business occurs smoothly and that we realize estimated financial and operating results; if we do not meet these expectations, that could materially impact our revenues as well as our costs; and

•

the absence of any significant unanticipated or unusual charges.

These estimates also assume that we do not consummate any significant change in our operations such as significant acquisitions or dispositions. If one or more of our assumptions prove incorrect, our results will differ, and such differences could be material. Accordingly, prospective investors should not place undue reliance on these estimates, as they should not be regarded as a representation that the anticipated results will be achieved.

Non-GAAP Financial Measures

We have presented the non-GAAP financial measures Adjusted EBITDA and Available Cash before Reserves in this prospectus supplement. Our non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Adjusted EBITDA and Available Cash before Reserves measures are just two of the relevant data points considered from time to time.

When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team has access to a wide range of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information; various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures; income; cash flow; and expectations for us, and certain information regarding some of our peers. Additionally, our board of directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.

Adjusted EBITDA is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:

•

the financial performance of our assets without regard to financing methods, capital structures or historical cost basis;

•

our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure;

•

the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;

•

the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and

•

our ability to make certain discretionary payments, such as distributions on our units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.

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We define Adjusted EBITDA as net income or loss plus net interest expense, income taxes, depreciation and amortization plus other specific items, the most significant of which are the addition of cash received from direct financing leases not included in income, non-cash equity-based compensation expense, expenses related to acquiring assets that provide new sources of cash flow, the effects of available cash generated by equity method investees not included in income, and loss on redemption of senior notes. We also exclude the effect on net income or loss of unrealized gains or losses on derivative transactions.

Available Cash before Reserves, also referred to as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly traded partnerships and is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:

•

the financial performance of our assets;

•

our operating performance;

•

the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;

•

the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and

•

our ability to make certain discretionary payments, such as distributions on our units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.

We define Available Cash before Reserves as net income as adjusted for specific items, the most significant of which are the addition of certain non-cash expenses (such as depreciation and amortization), the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets), unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, the subtraction of maintenance capital utilized, and loss on redemption of senior notes.

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Summary Historical Combined Financial Data of the Enterprise Offshore Business

The summary historical financial data for the Enterprise Offshore Business were derived from the Enterprise Offshore Business historical financial statements and the related notes included elsewhere in this prospectus supplement. The summary historical financial data do not purport to project the Enterprise Offshore Business’ results of operations or financial position for any future period or as of any date and are not necessarily indicative of financial results to be achieved in future periods. You should read the summary financial data below together with “Offshore Business Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Enterprise Offshore Business historical consolidated financial statements and related notes included elsewhere in this prospectus supplement.

The Enterprise Offshore Business historical consolidated financial data as of and for the fiscal years ended December 31, 2014, 2013 and 2012 have been audited. The Enterprise Offshore Business historical consolidated financial statements as of and for the three months ended March 31, 2015 and 2014 are unaudited. The Enterprise Offshore Business believes that all material adjustments that consist only of normal recurring adjustments necessary for the fair presentation of its interim results have been included. Results of operations for any interim period are not necessarily indicative of the results of operations for the Enterprise Offshore Business’ entire fiscal year.


	Three months ended March 31,						Year ended December 31,
($ in millions)	2015			2014			2014			2013			2012
Income Statement Data:
Revenues	$	41.1		$	44.4		$	184.4		$	187.9		$	228.3
Costs and expenses		41.7			41.1			180.1			178.7			185.9
Equity in income of unconsolidated affiliates		19.1			11.1			55.2			29.8			26.8
Net income attributable to Enterprise Offshore Business		18.8			14.4			59.9			37.9			64.5
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	53.0		$	39.0		$	175.7		$	149.5		$	173.9
Investing activities		2.2			(2.8	)		13.6			(46.0	)		(72.0	)
Financing activities		(54.5	)		(36.3	)		(189.1	)		(105.4	)		(102.4	)
Balance Sheet Data (at end of period):
Cash and cash equivalents	$	2.7					$	2.0		$	1.8
Total assets		1,765.9						1,796.0			1,920.3
Total liabilities		122.0						117.0			114.2
Total Equity		1,643.9						1,679.0			1,806.1

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RISK FACTORS

An investment in our common units involves risk. We urge you to read and consider carefully the following risk factors, the risk factors described under the caption “Risk Factors” beginning on page 2 of the accompanying base prospectus and those risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, which risk factors are incorporated by reference into this prospectus supplement, together with all of the other information included or incorporated by reference into this prospectus supplement, before deciding whether this investment is suitable for you. If any of these risks were to occur, our business, financial condition or results of operations could be materially and adversely affected. In such case, the trading price of the common units could decline, and you could lose all or part of your investment.

This offering is not conditioned upon the closing of the Enterprise Offshore Business Acquisition. Even if the Enterprise Offshore Business Acquisition is completed, we may fail to realize the growth prospects anticipated as a result of the Enterprise Offshore Business Acquisition.

On July 16, 2015, we signed the purchase and sale agreement for the Enterprise Offshore Business Acquisition. We expect the Enterprise Offshore Business Acquisition to close in the third quarter of 2015, subject to customary closing conditions. All of the closing conditions, other than those that, by their nature, are to be satisfied at the closing, have been satisfied or waived. However, certain conditions to the closing of the Enterprise Offshore Business Acquisition that are to be satisfied at the closing, including the absence of any governmental or judicial action prohibiting or making illegal the completion of the Enterprise Offshore Business Acquisition and the accuracy of each party’s representations and warranties in the purchase and sale agreement, are outside of our control. Completion of the Enterprise Offshore Business Acquisition is not a condition to completion of this offering of common units, and there can be no assurance that the Enterprise Offshore Business Acquisition will be completed.

There are a number of risks and uncertainties relating to the Enterprise Offshore Business Acquisition. For example, the Enterprise Offshore Business Acquisition may not be completed, or may not be completed in the time frame, on the terms, or in the manner currently anticipated. There can be no assurance that events will not intervene to delay or result in the failure to close the Enterprise Offshore Business Acquisition. In addition, both we and EPO have the ability to terminate the purchase and sale agreement under certain circumstances. Failure to complete the Enterprise Offshore Business Acquisition would prevent us from realizing the anticipated benefits of the Enterprise Offshore Business Acquisition. We would also remain liable for significant transaction costs, including legal, accounting and financial advisory fees. In addition, the market price of our common units may reflect various market assumptions as to whether the Enterprise Offshore Business Acquisition will be completed. Consequently, the completion of, the failure to complete, or any delay in the closing of the Enterprise Offshore Business Acquisition could result in a significant change in the market price of our common units.

The pro forma financial statements included in this prospectus supplement are presented for illustrative purposes only and may not be an indication of our financial condition or results of operations following the Enterprise Offshore Business Acquisition.

The pro forma financial statements included in this prospectus supplement and our statements in “Summary— Pending Acquisition of Enterprise Offshore Pipelines and Services Business—Rationale for Enterprise Offshore Business Acquisition” are presented for illustrative purposes only, are based on various adjustments and assumptions, many of which are preliminary, and may not be an indication of our financial condition or results of operations following the Enterprise Offshore Business Acquisition. Our actual financial condition and results of operations following the Enterprise Offshore Business Acquisition may not be consistent with, or evident from, these pro forma financial statements and other statements relating to the Enterprise Offshore Business Acquisition. In addition, the assumptions used in preparing the pro forma financial data and estimates may not prove to be accurate, and other factors may affect our financial condition or results of operations following the Enterprise Offshore Business Acquisition. In addition,

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completion of the Enterprise Offshore Business Acquisition is not a condition to completion of this offering of common units. Therefore, investors should refer to our historical financial statements incorporated by reference in this prospectus supplement when evaluating an investment in our common units.

We may not be able to obtain debt financing for the Enterprise Offshore Business Acquisition on expected or acceptable terms, which could make the Enterprise Offshore Business Acquisition less accretive.

We intend to finance the Enterprise Offshore Business Acquisition with the net proceeds from this offering, borrowings under our expanded revolving credit facility and the net proceeds of the concurrent senior notes offering. We and our subsidiary co-issuer may not be able to issue the notes on expected or acceptable terms, in which case we would fund a portion of the Enterprise Offshore Business Acquisition through the bridge facility, which would make the Enterprise Offshore Business Acquisition less accretive.

As a result of the additional indebtedness we will incur to consummate the Enterprise Offshore Business Acquisition, we may experience a potential material adverse effect on our financial condition and results of operations.

The closing of the Enterprise Offshore Business Acquisition is not subject to a financing condition. We plan to finance the Enterprise Offshore Business Acquisition with the net proceeds from this offering, borrowings under our revolving credit facility and the net proceeds from the concurrent senior notes offering.

Our increased indebtedness could also have adverse consequences on our business, such as:

•

requiring us to use a substantial portion of our cash flow from operations to service our indebtedness, which would reduce the available cash flow to fund working capital, capital expenditures, development projects and other general partnership purposes and reduce cash available for distributions;

•

limiting our ability to obtain additional financing to fund our working capital needs, acquisitions, capital expenditures or other debt service requirements or for other purposes;

•

increasing the costs of incurring additional debt;

•

limiting our ability to compete with other companies that are not as highly leveraged, as we may be less capable of responding to adverse economic and industry conditions;

•

restricting us from making strategic acquisitions, developing properties or exploiting business opportunities;

•

restricting the way in which we conduct our business because of financial and operating covenants in the agreements governing our existing and future indebtedness;

•

exposing us to potential events of default (if not cured or waived) under covenants contained in our debt instruments that could have a material adverse effect on our business, financial condition and operating results; and

•

limiting our ability to react to changing market conditions in our industry.

The impact of any of these potential adverse consequences could have a material adverse effect on our results of operations, financial condition and liquidity.

As a result of the Enterprise Offshore Business Acquisition, we anticipate that the scope and size of our operations and business will substantially change. We cannot provide assurance that our expansion in scope and size will be successful.

We anticipate that the Enterprise Offshore Business Acquisition will substantially expand the scope and size of our business by adding substantial offshore operations to our existing offshore business. The

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anticipated future growth of our business will impose significant added responsibilities on management, including the need to identify, recruit, train and integrate additional employees. Our senior management’s attention may be diverted from the management of daily operations to the integration of the assets acquired in the Enterprise Offshore Business Acquisition. Our ability to manage our business and growth will require us to continue to improve our operational, financial and management controls, reporting systems and procedures. We may also encounter risks, costs and expenses associated with any undisclosed or other unanticipated liabilities and use more cash and other financial resources on integration and implementation activities than we expect. We may not be able to successfully integrate the Enterprise Offshore Business into our existing operations or realize the expected economic benefits of the Enterprise Offshore Business Acquisition, which may have a material adverse effect on our business, financial condition and results of operations, including our distributable cash flow.

Failure to successfully combine our business with the assets to be acquired in the Enterprise Offshore Business Acquisition, or an inaccurate estimate by us of the benefits to be realized from the Enterprise Offshore Business Acquisition, may adversely affect our future results.

The Enterprise Offshore Business Acquisition involves potential risks, including:

•

the failure to realize expected profitability, growth or accretion;

•

environmental or regulatory compliance matters or liabilities;

•

title or permit issues;

•

the incurrence of significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; and

•

the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.

The expected benefits from the pending Enterprise Offshore Business Acquisition may not be realized if our estimates of the potential net cash flows associated with the assets to be acquired by us in the Enterprise Offshore Business Acquisition are materially inaccurate or if we fail to identify operating issues or liabilities associated with the assets prior to closing. The accuracy of our estimates of the potential net cash flows attributable to such assets is inherently uncertain. If certain issues are identified after closing of the Enterprise Offshore Business Acquisition, the purchase and sale agreement provides for limited recourse against EPO.

If we close the Enterprise Offshore Business Acquisition and if any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of the Enterprise Offshore Business Acquisition may not be fully realized, if at all, and our future financial condition, results of operations and distributable cash flow could be negatively impacted.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or cause us to change our business activities, affect the tax considerations of an investment in us and change the character or treatment of portions of our income. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would adversely affect the tax treatment of certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships.

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On May 5, 2015, the U.S. Treasury Department and the IRS released proposed regulations (the “Proposed Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code. The U.S. Treasury Department and the IRS have requested comments from industry participants regarding the standards set forth in the Proposed Regulations. The Proposed Regulations provide an exclusive list of industry-specific activities and certain limited support activities that generate qualifying income. Although the Proposed Regulations adopt a narrow interpretation of the activities that generate qualifying income, we believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the Proposed Regulations. However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation of Section 7704 of the Code. If the regulations in their final form were to treat any material portion of our income we treat as qualifying income as non-qualifying income, we anticipate being able to treat that income as qualifying income for ten years under special transition rules provided in the Proposed Regulations.

We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could cause a material reduction in our anticipated cash flows and could cause us to be treated as an association taxable as a corporation for U.S. federal income tax purposes subjecting us to the entity-level tax and adversely affecting the value of our common units.

USE OF PROCEEDS

We expect to receive net proceeds from this offering of approximately $ million, after deducting the underwriters’ discounts and payment of estimated offering expenses. We intend to use the net proceeds, including any net proceeds from the underwriters’ exercise of their option to purchase additional common units, to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition and any remaining net proceeds for general partnership purposes, including funding acquisitions (including organic growth projects) or repaying a portion of the borrowings outstanding under our revolving credit facility. If the Enterprise Offshore Business Acquisition does not close, we intend to use all of the net proceeds, including any net proceeds from the underwriters’ exercise of their option to purchase additional common units, for general partnership purposes, including funding acquisitions (including organic growth projects) or repaying a portion of the borrowings outstanding under our revolving credit facility.

Our revolving credit facility matures in July 2019 and bears interest at a variable rate, which was approximately 2.76% per annum as of June 30, 2015. Our outstanding borrowings under our revolving credit facility were incurred in connection with organic growth projects, funding capital expenditures and general working capital purposes. We also intend to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition with borrowings under our revolving credit facility.

Certain of the underwriters or their affiliates participating in this offering are lenders under our revolving credit facility and may receive a portion of the proceeds of this offering through the repayment by us of outstanding borrowings under our revolving credit facility with such proceeds. Please read “Underwriting” for further details.

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CAPITALIZATION

The following table sets forth our consolidated cash and cash equivalents and capitalization as of March 31, 2015:

(1)	on a historical basis;

(2)

on an as adjusted basis to give effect to (a) the April 2015 common units offering and the application of the net proceeds to repay $198.2 million of borrowings outstanding under our revolving credit facility, (b) the May 2015 notes offering and the application of the net proceeds to fund the 2018 notes tender offer and redemption and repay $34.7 million in borrowings outstanding under our revolving credit facility, and (c) the 2018 notes tender offer and redemption; and

(3)

on a pro forma, as further adjusted basis to give effect to (a) the transactions described in (2), (b) the sale and issuance of 9,000,000 common units pursuant to this offering at an assumed public offering price of $46.49 per common unit, which was the closing price of our common units on the NYSE on July 15, 2015, and the application of the estimated $403.4 million net proceeds therefrom to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition, (c) the sale and issuance of $750,000,000 aggregate principal amount of senior notes pursuant to the concurrent senior notes offering and the application of the estimated $736.9 million net proceeds therefrom to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition, (d) estimated borrowings of $395.8 million under our revolving credit facility to fund a portion of the purchase price for the Enterprise Offshore Business Acquisition and to pay estimated offering and transaction expenses, and (e) the closing of the Enterprise Offshore Business Acquisition.

The following table should be read together with our historical financial statements and the related notes thereto that are incorporated by reference into this prospectus supplement. This offering of common units is not contingent upon the closing of the concurrent senior notes offering or the closing of the Enterprise Offshore Business Acquisition and the concurrent senior notes offering is not contingent upon the closing of this offering of common units


	As of March 31, 2015
	Historical		As adjusted		Pro forma, as further adjusted
	(in millions)
Cash and cash equivalents	$	11.1	$	11.1	$
Long-term debt:
Revolving credit facility due July 2017(1)(2)		648.4		415.5
2018 Notes (including unamortized premium of $604)		350.6		—		—
2021 Notes		350.0		350.0		350.0
2023 Notes		—		400.0		400.0
2024 Notes		350.0		350.0		350.0
2022 Notes offered concurrently		—		—		750.0
Total long-term debt		1,699.0		1,515.5
Partners’ capital:
Common unitholders		1,192.9		1,372.5

Total capitalization	$	2,891.9	$	2,888.0	$

(1)	Does not include $11.2 million in outstanding letters of credit.

(2)	On July 16, 2015, we received commitments to increase the committed amount under our revolving credit facility from $1.0 billion to $1.5 billion effective as of the closing of the Enterprise Offshore Business Acquisition.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

Our common units trade on the NYSE under the symbol “GEL.” As of July 15, 2015, there were 99,589,221 common units outstanding, held by approximately 47,800 record holders and beneficial owners (held in street name).

We are required by our partnership agreement to distribute 100% of our available cash within 45 days after the end of each quarter to our common unitholders of record. There is no guarantee that we will pay a distribution on our units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or if an event of default then exists, under our revolving credit facility. Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. Cash reserves are generally the amounts deemed necessary or appropriate, in the reasonable discretion of our general partner, to provide for the proper conduct of our business or to comply with applicable law, any of our debt instruments or other agreements. The full definition of available cash is set forth in our partnership agreement and amendments thereto. Please read “Where You Can Find More Information.”

In addition, our partnership agreement authorizes us to issue additional equity interests in our partnership with such rights, powers and preferences (which may be senior to our common units) as our general partner may determine in its sole discretion, including with respect to the right to share in distributions and profits and losses of the partnership.

The following table sets forth the high and low sales prices for our common units in each quarter, as reported by the NYSE, and the declared cash distributions for our common units in each quarter.


	Price range per common unit				Cash distribution per common unit(1)(2)
	High		Low		Cash distribution per common unit(1)(2)
Fiscal Year Ending December 31, 2015
Third Quarter (through July 15, 2015)	$	48.15	$	43.44	$	0.625
Second Quarter		50.04		43.44		0.610
First Quarter		48.66		38.65		0.595
Fiscal Year Ended December 31, 2014
Fourth Quarter	$	53.22	$	34.57	$	0.580
Third Quarter		56.88		50.38		0.565
Second Quarter		57.47		52.60		0.550
First Quarter		56.80		49.46		0.535
Fiscal Year Ended December 31, 2013
Fourth Quarter	$	53.94	$	48.00	$	0.5220
Third Quarter		55.99		45.81		0.5100
Second Quarter		54.91		44.04		0.4975
First Quarter		49.34		36.00		0.4850

(1)	Cash distributions are shown in the quarter paid.

(2)	The distribution attributable to the quarter ended June 30, 2015 will be paid on August 14, 2015 to unitholders of record at the close of business on July 31, 2015.

The last reported sales price of our common units on the NYSE on July 15, 2015, was $46.49 per common unit.

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GENESIS ENERGY, L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Introduction

The following Unaudited Pro Forma Condensed Consolidated Balance Sheet as of March 31, 2015 and the Unaudited Pro Forma Condensed Consolidated Statement of Operations for the year ended December 31, 2014 and the three months ended March 31, 2015 give effect to the proposed acquisition (the “Acquisition”) by Genesis Energy, L.P. (“Genesis”) of the Offshore Gulf of Mexico Energy Services Business (the “Enterprise Offshore Business”) of Enterprise Products Operating, LLC (“Enterprise”) for $1.5 billion and the related assumptions and adjustments described in the notes thereto. These statements will be referred to as the Unaudited Pro Forma Statements.

For purposes of preparing this data, the $1.5 billion of financing to be obtained by Genesis in connection with the Acquisition is assumed to be financed by net proceeds of a public offering of common units of $403.4 million, new indebtedness of approximately $750 million from the issuance of new senior unsecured notes and additional borrowings of $363.2 million (inclusive of an assumed net working capital amount of approximately $16.6 million to be included in the purchase price) under our senior secured credit facility. Such amounts do not include assumed additional borrowings under our senior secured credit facility to finance assumed transaction costs to be incurred as a result of the Acquisition. See further discussion of such items in the accompanying footnotes.

As of the date of these Unaudited Pro Forma Statements, Genesis has not performed detailed valuation studies to determine the required estimates of the fair value of the Enterprise Offshore assets to be acquired and the liabilities to be assumed. Accordingly, the pro forma adjustments for the Acquisition are preliminary and subject to further adjustments as additional information become available and the various analyses and other valuations are performed. Such adjustments may have a significant effect on total assets, total liabilities, total equity, operating expenses and depreciation and amortization expenses. The preliminary pro forma adjustments have been made solely for the purposes of providing the Unaudited Pro Forma Statements.

The Unaudited Pro Forma Statements are based upon the historical unaudited and audited financial statements of the Enterprise Offshore Business, which are included in Exhibit 99.4 in Genesis’ Current Report on Form 8-K filed on July 16, 2015, the unaudited condensed consolidated financial statements of Genesis for the three months ended March 31, 2015 as included in Genesis’ Form 10-Q, as amended and superseded in part in Genesis’ Current Report on Form 8-K filed on July 2, 2015, and the audited consolidated financial statements of Genesis for the year ended December 31, 2014 as included in Genesis’ Form 10-K for the fiscal year then ended, as amended and superseded in part in Genesis’ Current Report on Form 8-K filed on July 2, 2015. The Unaudited Pro Forma Statements have been compiled in a manner consistent with the accounting policies adopted by Genesis.

The Enterprise Offshore Business includes a 50% interest in Cameron Highway Oil Pipeline Company (“CHOPS”) and a 50% interest in Southeast Keathley Canyon Pipeline Company, L.L.C (“SEKCO”). Prior to this proposed acquisition, Genesis owns 50% of each of CHOPS and SEKCO, respectively. The Unaudited Pro Forma Condensed Consolidated Balance Sheet includes the effects of the re-measurement of Genesis’ pre-acquisition, historical interest in each of CHOPS and SEKCO at fair value based on accounting guidance involving step acquisitions as discussed in ASC 805-10-25. The value assigned in the purchase price allocation to the interest to be acquired in CHOPS and SEKCO from Enterprise is used as a basis in calculating the fair value of Genesis’ historical interest in each of CHOPS and SEKCO.

The Unaudited Pro Forma Statements of Genesis should be read in conjunction with the audited consolidated financial statements and notes thereto included in Genesis’ Annual Report on Form 10-K for the year ended December 31, 2014, as amended and superseded in part in Genesis’ Current Report on Form 8-K filed on July 2, 2015, the unaudited consolidated financial statements and notes thereto included in Genesis’ Quarterly Report on Form 10-Q for the three months ended March 31, 2015, as amended and

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superseded in part in Genesis’ Current Report on form 8-K filed on July 2, 2015, and the audited and unaudited financial statements of Enterprise Offshore included in Exhibit 99.4 in Genesis’ Current Report on Form 8-K filed on July 16, 2015.

The Unaudited Pro Forma Statements were prepared assuming that the acquisition by Genesis of the Enterprise Offshore Business was consummated as of March 31, 2015 for the Unaudited Pro Forma Condensed Consolidated Balance Sheet and as of January 1, 2014 for the Unaudited Pro Forma Condensed Consolidated Statements of Operations. The Unaudited Pro Forma Statements have been prepared based upon assumptions deemed appropriate by Genesis and may not be indicative of actual results.

The historical consolidated financial information has been adjusted in the Unaudited Pro Forma Statements to give effect to pro forma events that are:

•

directly attributable to the Acquisition;

•

factually supportable; and

•

with respect to the unaudited pro forma combined condensed statements of operations, expected to have a continuing impact on the combined results of Genesis and Enterprise Offshore.

The Unaudited Pro Forma Statements do not reflect any cost savings (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the Acquisition.

The Unaudited Pro Forma Statements do not include the effects of the completion of an offering of 4.6 million common units in a public offering in April 2015, resulting in net proceeds of approximately $198 million. Such net proceeds were used for general partnership purposes, including the repayment of a portion of the borrowings outstanding under Genesis’ revolving credit facility. The Unaudited Pro Forma Statements also do not include the effects of a public offering of $400 million in aggregate principal amount of 6% senior unsecured notes due 2023. The proceeds from that notes offering were used to fund the purchase price of $300.1 million of Genesis’ 7.875% senior unsecured notes due 2018 that were tendered in May 2015 and the redemption of the remaining $49.9 million of Genesis’ 7.875% senior unsecured notes due 2018 that were redeemed in June 2015.

Assumptions and estimates underlying the unaudited pro forma combined condensed adjustments are described in the accompanying notes, which should be read in connection with the Unaudited Pro Forma Statements. Since the Unaudited Pro Forma Statements have been prepared in advance of the close of the Acquisition, the final amounts recorded upon closing may differ materially from the information presented. These estimates are subject to change pending further review of the assets acquired and liabilities assumed and additional information available at the time of closing.

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GENESIS ENERGY, L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

March 31, 2015

(in millions)


	Historical Genesis		Enterprise Offshore Business		Pro Forma Adjustments					Pro Forma Adjustments to Consolidate Historically Held Equity Investments (A)			Pro Forma Genesis
ASSETS
Cash and cash equivalents	$	11.1	$	2.7	$	750.0		(B	)	$	1.1		$	14.9
						403.4		(B	)
						377.3		(B	)
						(1,516.6	)	(D	)
						(14.1	)	(E	)
						18.5		(F	)
						(18.5	)	(F	)
Accounts receivable—trade, net		202.6		24.9							12.1			239.6
Inventories		63.8									0.3			64.1
Other		30.4		2.1							1.3			33.8

Total current assets		307.9		29.7		0.0					14.8			352.4
Fixed assets, net		1,730.2		1,126.0		(640.2	)	(D	)		1,532.1			3,748.2
Investment in direct financing leases, net		144.5												144.5
Equity investees		620.1		487.6		678.1		(D	)		(1,541.0	)		547.9
						303.1		(C	)
Intangible assets, net		79.9		39.3		(39.3	)	(D	)					79.9
Goodwill		325.0		82.0		(82.0	)	(D	)					325.0
Other assets, net		64.5		1.3		18.5		(F	)		1.6			84.6
						(1.3	)	(D	)

Total assets	$	3,272.1	$	1,765.9	$	236.9				$	7.5		$	5,282.5

LIABILITIES AND PARTNERS’ CAPITAL
Accounts payable—trade	$	203.3	$	7.9						$	3.3		$	214.5
Accrued and other current liabilities		139.3		16.9							2.2			158.4

Total current liabilities		342.6		24.8		0.0					5.5			372.9
Senior secured credit facility		648.4				377.3		(B	)					1,044.2
						18.5		(F	)
Senior unsecured notes		1,050.6				750.0		(B	)					1,800.6
Deferred tax liabilities		19.3												19.3
Other long-term liabilities		18.3		97.2		49.2		(D	)		2.0			166.7
Partners’ capital:
Common unitholders		1,192.9		1,580.8		(1,580.8	)	(D	)		0.0			1,885.4
						403.4		(B	)
						303.1		(C	)		0.0
						(14.1	)	(E	)
Noncontrolling Interest				63.1		(69.7	)	(D	)					(6.6	)

Total partners’ capital		1,192.9		1,643.9		(958.1	)				0.0			1,878.8

Total liabilities and partners’ capital	$	3,272.1	$	1,765.9	$	236.9				$	7.5		$	5,282.5

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

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GENESIS ENERGY, L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

For the Three Months Ended March 31, 2015

(in millions, except per common unit amounts)


	Historical Genesis			Enterprise Offshore Business			Pro Forma Adjustments				Pro Forma Adjustments to Consolidate Historically Held Equity Investments (G)			Pro Forma Genesis
REVENUES	$	526.8		$	41.1						$	36.6		$	604.5
COSTS AND EXPENSES:
Cost of sales and operating expenses		461.7			17.0							7.1			485.8
General and administrative expenses		13.2			1.3										14.5
Depreciation and amortization expense		27.1			23.4			(14.1	)	(H)		11.0			47.4

Total costs and expenses		502.0			41.7			(14.1	)			18.1			547.7

OPERATING INCOME		24.8			(0.6	)		14.1				18.5			56.8
Equity in earnings of equity investees		15.5			19.1			(2.1	)	(I)		(18.5	)		13.2
								(0.8	)	(J)
Interest expense		(19.2	)					(14.1	)	(K)					(33.3	)

Income before income taxes		21.1			18.5			(2.9	)			—			36.7
Income tax expense		(0.9	)												(0.9	)

NET INCOME		20.2			18.5			(2.9	)			—			35.8
Net income (loss) attributable to noncontrolling interest					0.3			(0.7	)	(L)					(0.4	)

NET INCOME ATTRIBUTABLE TO COMMON UNITHOLDERS	$	20.2		$	18.8		$	(3.6	)		$	—		$	35.4

Net income attributable to common unitholders per common unit:
Basic and Diluted	$	0.21												$	0.34
Weighted average common units:
Basic and Diluted		95.0						9.0		(M)					104.0

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

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GENESIS ENERGY, L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

For the Twelve Months Ended December 31, 2014

(in millions, except per common unit amounts)


	Historical Genesis			Enterprise Offshore Business		Pro Forma Adjustments					Pro Forma Adjustments to Consolidate Historically Held Equity Investments (G)			Pro Forma Genesis
REVENUES	$	3,846.2		$	184.4						$	105.4		$	4,136.0
COSTS AND EXPENSES:
Cost of sales and operating expenses		3,572.0			84.0							17.1			3,673.1
General and administrative expenses		50.7			7.5										58.2
Depreciation and amortization expense		90.9			88.6		(56.2	)	(H)			36.0			159.3

Total costs and expenses		3,713.6			180.1		(56.2	)				53.1			3,890.6

OPERATING INCOME		132.6			4.3		56.2					52.3			245.4
Equity in earnings of equity investees		43.1			55.2		(8.4	)	(I)			(52.3	)		30.8
							(6.8	)	(J)
Interest expense		(66.6	)				(56.4	)	(K)						(123.0	)

Income before income taxes		109.1			59.5		(15.4	)				—			153.2
Income tax expense		(2.9	)												(2.9	)

NET INCOME		106.2			59.5		(15.4	)				—			150.3
Net income (loss) attributable to noncontrolling interest					0.4		(2.9	)	(L)						(2.5	)

NET INCOME ATTRIBUTABLE TO COMMON UNITHOLDERS	$	106.2		$	59.9	$	(18.3	)			$	—		$	147.8

Net income attributable to common unitholders per common unit:
Basic and Diluted	$	1.18												$	1.49
Weighted average common units:
Basic and Diluted		90.1					9.0		(M	)					99.1

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

S-32

GENESIS ENERGY, L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

(in millions, except where otherwise indicated, or amounts per unit)

1. Basis of Pro Forma Presentation

The unaudited pro forma combined condensed financial information was prepared using the acquisition method of accounting and was based on the historical consolidated financial statements of Genesis Energy, L.P. (“Genesis”) and the Offshore Gulf of Mexico Energy Services Business of Enterprise Products Operating, LLC (“Enterprise Offshore”) after giving effect to Genesis’ contemplated acquisition of Enterprise Offshore and related financing arrangements. All pro forma statements use Genesis’ period end date.

The allocation of the purchase price used in the Unaudited Pro Forma Statements is based on preliminary estimates of the fair value of assets acquired and liabilities assumed. Genesis expects the purchase price allocation to be completed upon the finalization of the related valuations and analyses. The final valuations may be materially different from the preliminary valuations. The pro forma adjustments included herein may be revised as additional information becomes available and as additional analyses and valuations are performed. The final allocation of the purchase price will be determined after the acquisition is completed and after completion of a final analysis to determine the fair values of the tangible assets, identifiable intangible assets, and liabilities as of the date the acquisition is complete. Accordingly, the final purchase accounting adjustments may be materially different from the pro forma adjustments presented in the Unaudited Pro Forma Statements. Increases or decreases in the fair value of the net assets may change the amount of the purchase price allocated to various assets and liabilities. This may impact the unaudited pro forma condensed combined statements of operations due to an increase or decrease in the amount of amortization or depreciation of the adjusted assets.

The acquisition method of accounting is based on Accounting Standards Codification, ASC, Topic 805, “Business Combinations,” and uses the fair value concepts defined in ASC Subtopic 820-10, “Fair Value Measurement.” ASC Topic 805 requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the Acquisition date.

ASC Subtopic 820-10 defines the term “fair value” and sets forth the valuation requirements for any asset or liability measured at fair value, expands related disclosure requirements and specifies a hierarchy of valuation techniques based on the nature of the inputs used to develop the fair value measures. Fair value is defined in ASC Subtopic 820-10 as ‘‘the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” This is an exit price concept for the valuation of the asset or liability. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability. Fair value measurements for an asset assume the highest and best use by these market participants. As a result of these standards, Genesis may be required to record assets that are not intended to be used or sold and/or to value assets at fair value measures that do not reflect Genesis’ intended use of those assets. Many of these fair value measurements can be highly subjective and it is also possible that other professionals, applying reasonable judgment to the same facts and circumstances, could develop and support a range of alternative estimated amounts.

Under the acquisition method of accounting, the assets acquired and liabilities assumed will be recorded as of the completion of the acquisition, at their respective fair values and consolidated with those of Genesis. Financial statements and reported results of operations of Genesis issued after completion of the acquisition will reflect these values. Periods prior to completion of the acquisition will not be retroactively restated to reflect the historical financial position or results of operations of Enterprise Offshore.

S-33

GENESIS ENERGY, L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(in millions, except where otherwise indicated, or amounts per unit)

Under ASC Subtopic 805-10, transaction costs (e.g., advisory, legal, other professional fees) and certain restructuring charges impacting the target company are not included as a component of consideration transferred but are accounted for as expenses in the periods in which the costs are incurred. Total transaction costs expected to be incurred by Genesis are estimated to be $14.1 million.

The unaudited pro forma condensed financial statements are not intended to represent or be indicative of the consolidated results of operations or financial position of Genesis that would have been reported had the Acquisition been completed as of the dates presented, and should not be taken as representative of the future consolidated results of operations or financial position of Genesis. The unaudited pro forma condensed financial statements should be read in conjunction with Genesis financial statements for the three months ended March 31, 2015 and for the year ended December 31, 2014, which are included in its Annual Report on Form 10-K for the year ended December 31, 2014, as amended and superseded in part in its Current Report on Form 8-K filed on July 2, 2015, and in Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, as amended and superseded in part in its Current Report on Form 8-K filed on July 2, 2015. Enterprise Offshore’s combined financial statements as of March 31, 2015, December 31, 2014 and 2013 and for the three years ended December 31, 2014, and for the quarterly periods ended March 31, 2015 and 2014 are included in Genesis’ Current Report on Form 8-K filed on July 16, 2015.

2. Description of the Transaction

On July 16, 2015, Genesis Energy, L.P. entered into a purchase and sale agreement with Enterprise Products Operating, LLC pursuant to which it will acquire all of the equity interests in the Offshore Gulf of Mexico Energy Services Business of Enterprise Products Operating, LLC upon the terms and subject to the conditions set forth in the purchase and sale agreement. The consideration for the Enterprise Offshore acquisition is comprised of $1.5 billion in cash, subject to certain post-closing adjustments for working capital. As detailed in the purchase and sale agreement, the purchase price will be adjusted based upon Enterprise Offshore’s net assets on a date prior to the closing date. This purchase price adjustment is to be determined and agreed to after closing, subject to a review period.

The purchase and sale agreement contains customary representations and warranties, covenants and agreements. The purchase and sale agreement also contains customary termination rights for both parties. The Enterprise Offshore acquisition is expected to close in July 2015, subject to satisfaction or waiver of customary closing conditions. The Company’s obligation to close the Enterprise Offshore acquisition is not subject to any condition related to the availability of financing.

3. Financing of the Transaction

These Unaudited Pro Forma Statements reflect Genesis’ acquisition of Enterprise Offshore through an assumed combination of the cash proceeds from the issuance of approximately $750 million of senior unsecured notes and net cash proceeds of approximately $403.4 million from the issuance of common units (9,000,000 common units at an assumed offering price of $46.49 per common unit based on the closing price as of July 15, 2015, net of underwriting discounts and offering costs) of Genesis Energy, L.P. and $395.8 million from total additional borrowings under our under our senior secured credit facility. In addition to financing the $1.5 billion preliminary purchase price, these financing assumptions also include an adjustment for $16.6 million in estimated net working capital reflected in the financial statements of Enterprise Offshore to be purchased prior to closing. These amounts also include additional borrowings under our senior secured credit facility to finance a portion of our transaction related costs assumed to be

S-34

GENESIS ENERGY, L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(in millions, except where otherwise indicated, or amounts per unit)

incurred. All associated fees related to the acquisition of Enterprise Offshore and the issuance of long term debt and equity have been reflected in the pro forma financial statements. A summary of assumed financing related items resulting from the Acquisition is shown below:


Financing Item	Amount (in millions)
Proceeds from Issuance of Common Units	$	403.4
Proceeds from Issuance of Senior Unsecured Notes		750.0
Additional Borrowings Under Senior Secured Credit Facility to Finance Base Purchase Price		346.6
Additional Borrowings Under Senior Secured Credit Facility to Finance Working Capital Purchase		16.6
Additional Borrowings Under Senior Secured Credit Facility to Finance Note Issuance and Credit Facility Related Costs		18.5
Additional Borrowings Under Senior Secured Credit Facility to Finance Transaction and Financing Related Costs		14.1

Total Proceeds	$	1,549.2

4. Items Excluded from Unaudited Pro Forma Statements

Subsequent to March 31, 2015, Genesis completed several financing related transactions that were not directly attributable to this proposed acquisition.

On April 10, 2015, Genesis completed an underwritten public offering of common units. Including the overallotment option, which was exercised in full by the underwriters, the Genesis sold a total of 4,600,000 common units at $44.42 per common unit. Total net proceeds from the offering, after deducting underwriting discounts and commissions and estimated offering expenses, were approximately $198 million. Genesis has used these net proceeds for general partnership purposes, including the repayment of a portion of the borrowings outstanding under its revolving credit facility.

On May 20, 2015, Genesis completed a cash tender offer to purchase outstanding principal amounts on its 7.875% senior notes due 2018. As of this date, $350 million aggregate principal amount of the notes were outstanding. As of the expiration of the tender offer on May 20, 2015, $300 million aggregate principal amount of the outstanding notes were validly tendered. For the outstanding remaining notes not tendered, Genesis redeemed all remaining outstanding notes in June 2015.

On May 21, 2015, Genesis completed an offering of $400 million of 6.0% senior unsecured notes due 2023.

The estimated net second quarter financial impact of the notes transactions discussed above (including the $400 million notes offering due 2023, as well as the tender/redemption of the $350 million notes due 2018) include an estimated $49 million in additional senior secured notes outstanding, repayment of an estimated $16 million of borrowings outstanding under Genesis’ revolving credit facility and an estimated $15 million non-cash loss to be recorded relating to the extinguishment of $350 million 2018 notes discussed above.

As the financing transactions mentioned above were not directly attributable to the proposed acquisition, they are excluded from the pro forma adjustments included in this Current Report on Form 8-K.

S-35

GENESIS ENERGY, L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(in millions, except where otherwise indicated, or amounts per unit)

5. Estimate of Assets Acquired and Liabilities Assumed

The preliminary estimate of the fair values of assets acquired and liabilities assumed as of the closing of the Acquisition were allocated to each of Enterprise Offshore’s assets and liabilities, pending Genesis’s completion of its purchase price allocation after closing once final analyses and valuations can be completed. Genesis cannot currently estimate the value of the purchase price to be allocated to property, plant and equipment, goodwill or identifiable intangible assets at this time. As a result, for purposes of this pro forma presentation, the net of the purchase price in excess of estimated preliminary fair value assigned to noncontrolling interest, other long term liabilities, other assets, equity investment interests to be acquired and working capital (related to current assets and current liabilities to be assumed) has been reflected in property, plant and equipment. The results of final analyses and valuations may reflect a value for certain customer contracts or other identifiable intangible assets, the quantification of which cannot be determined at this time.

The preliminary estimates of fair values of assets acquired and liabilities assumed (in millions), including a preliminary allocation based on the historical presentation of CHOPS and SEKCO as equity investments as well as and allocation adjusted for the consolidation of CHOPS and SEKCO, are as follows:


	Preliminary Amount Allocated (in millions)			Adjustment for CHOPS and SEKCO Consolidation			Amount Allocated (in millions)
Cash	$	—		$	0.6		$	0.6
Accounts Receivable		0.0			6.1			6.1
Inventories		0.0			0.2			0.2
Other Current		0.0			0.7			0.7
Property, Plant, Equipment		485.9			765.9			1,251.8
Equity Investees		1,163.7			(769.5	)		394.2
Other Assets		0.0			0.8			0.8
Accounts Payable		0.0			(1.7	)		(1.7	)
Accrued Liabilities and other current liabilities		0.0			(1.1	)		(1.1	)
Current ARO		(11.7	)					(11.7	)
Other Long-term Liabilities		(144.5	)		(2.0	)		(146.5	)
Noncontrolling Interest		6.6			0.0			6.6

Purchase Price	$	1,500.0		$	(0.0	)	$	1,500.0

Estimated Working Capital Adjustment								16.6

Net Purchase Price							$	1,516.6

The $1,251.8 million assigned to Property, Plant, and Equipment is estimated to be attributed to natural gas pipelines and equipment, offshore platforms, and crude oil pipelines. Within these categories, estimated useful lives range from 5 to 35 years for purposes of calculating estimated depreciation expense in these Unaudited Pro Forma Statements.

6. Adjustments to Unaudited Pro Forma Statements

(A) Reflects the consolidation of the historical financial statements of CHOPS and SEKCO as of March 31, 2015 on the unaudited pro forma condensed consolidated balance sheet (after giving effect to the estimated fair value of the acquired interest in each CHOPS and SEKCO as derived from the

S-36

GENESIS ENERGY, L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(in millions, except where otherwise indicated, or amounts per unit)

preliminary purchase price allocation) . Genesis owned 50% equity interest in each of CHOPS and SEKCO prior to this proposed acquisition and would own 100% equity interest in each of CHOPS and SEKCO assuming the acquisition of the 50% equity interest held by Enterprise in each of CHOPS and SEKCO. Genesis and Enterprise have historically accounted for their equity interest in each of CHOPS and SEKCO as equity method investments. Amounts include the 50% already owned by Genesis as well as the 50% portion attributable to the Acquisition. As such, these adjustments also reflect the elimination of the equity investments in CHOPS and SEKCO held by Genesis and Enterprise as of March 31, 2015. As 100% owner of all equity interests in CHOPS and SEKCO, Genesis will consolidate CHOPS and SEKCO in its consolidated financial statements.

(B) Reflects the assumed financing of the Acquisition. As previously mentioned, financing assumptions include the issuance of $403.4 million of new common units (9,000,000 units at a price of $46.49 per unit based on a closing price as of July 15, 2015, net of underwriting discounts and offering costs), $750 million of new senior unsecured notes, and $377.3 million of incremental borrowings under our senior secured credit facility. In addition to financing the $1.5 billion preliminary purchase price, these financing assumptions also include an adjustment to purchase $16.6 million in estimate net working capital reflected in the financial statements of the Enterprise Offshore Business to be purchased prior to closing, as well as additional borrowing under our credit facility to finance a portion of our transaction related costs assumed to be incurred.

(C) Reflects the step up to fair value of Genesis’ historically owned 50% interest in each of CHOPS and SEKCO as of March 31, 2015 (as historically accounted for as equity method investments). This step up of Genesis’ historical interest in CHOPS and SEKCO is based on the fair value assigned in the preliminary purchase price allocation to the 50% interest in CHOPS and 50% interest in SEKCO owned by Enterprise.

(D) Reflects the effects of the preliminary purchase price allocation relating to the Acquisition. This adjustment also reflects the removal of previously recorded goodwill, intangible assets and partners’ capital as recorded in the historic balance sheet of the Enterprise Offshore Business as of March 31, 2015 prior to applying the preliminary purchase price allocation. Additionally, this adjustment initially assumes applying the preliminary purchase price allocation to Genesis’ equity investments (assuming an additional 50% equity interest each) in CHOPS and SEKCO prior to adjusting for the consolidation of the entities as previously discussed. See Note 5 for further discussion surrounding the preliminary purchase price allocation.

(E) Reflects the estimated amounts relating to one-time transaction costs for various services and other payments necessary to complete the Acquisition.

(F) Reflects estimated new deferred debt issuance costs for the assumed $750 million issuance of senior unsecured notes to finance a portion of the Acquisition. This adjustment also reflects anticipated costs incurred in amending and restating Genesis’ credit agreement (with assumed upsizing of the senior secured credit facility), which will be assumed to occur as result of this Acquisition. Such items include legal fees, underwriting fees, bank fees and other services which would be amortized over the term of the notes and credit agreement respectively.

(G) Reflects the impact of the consolidation of the historical financial statements of CHOPS and SEKCO as of January 1, 2014 on the unaudited pro forma condensed consolidated statement of operations. Genesis owned 50% equity interest in each of CHOPS and SEKCO prior to this proposed acquisition and would own 100% equity interest in each CHOPS and SEKCO assuming the acquisition of the 50% equity interest held by Enterprise Offshore in each of CHOPS and SEKCO. Genesis and Enterprise Offshore have historically accounted for their equity interest in each of CHOPS and SEKCO as equity method investments.

S-37

GENESIS ENERGY, L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(in millions, except where otherwise indicated, or amounts per unit)

(H) Reflects change in depreciation resulting from the change in fair value and lives of tangible assets acquired from Enterprise Offshore (excluding CHOPS and SEKCO since these entities are now consolidated and discussed separately above) resulting from the preliminary purchase price allocation.

(I) Reflects change in amortization of excess purchase price (as compared to book value of equity interest) resulting from the change in fair value from preliminary purchase price allocation of the equity interest in Poseidon acquired from Enterprise.

(J) Reflects the change in equity income (before pro forma adjustment for consolidation of CHOPS and SEKCO) resulting from the changes in the fair value of our historically owned and acquired interests in CHOPS and SEKCO resulting from the preliminary purchase price allocation. See below for schedule:


	CHOPS 3/31/2015			SEKCO 3/31/2015			Total 3/31/2015
Reverse Equity Income — Genesis and Enterprise Offshore	$	(6.7	)	$	(12.6	)	$	(19.3	)
Add Historical Net Income — Genesis and Enterprise Offshore		8.3			15.3			23.6
Less Depreciation — PP&E from changes resulting from Purchase Price Allocation		(5.7	)		0.6			(5.1	)

Net Difference	$	(4.1	)	$	3.3		$	(0.8	)


	CHOPS 12/31/2014			SEKCO 12/31/2014			Total 12/31/2014
Reverse Equity Income — Genesis and Enterprise Offshore	$	(28.9	)	$	(30.2	)	$	(59.1	)
Add Book Net Income — Genesis and Enterprise Offshore		33.2			29.3			62.5
Less Depreciation — PP&E from changes resulting from Purchase Price Allocation		(11.5	)		1.4			(10.2	)

Net Difference	$	(7.2	)	$	0.5		$	(6.8	)

(K) Reflects increase in interest expense resulting from the assumed issuance of $750 million in senior unsecured notes and assumed incremental borrowings of $395.8 million under our senior secured credit facility resulting from the financing of this Acquisition and associated costs. Interest expense on the notes is calculated at an assumed annual interest rate of 6%. Interest expense on the incremental borrowing under our senior secured credit facility is calculated at an assumed annual interest rate of 2.5% (Genesis’ historic rate on LIBOR borrowing under its credit facility). This adjustment also reflects additional amortization of debt issuance costs related to the new senior unsecured note issuance, as well as the amortization of costs associated with an assumed credit agreement amendment. A 0.125% increase or decrease to the assumed interest rate on the borrowings would increase or decrease pro forma interest expense by approximately $1.4 million on an annual basis and $0.4 million on a quarterly basis.

(L) Reflects change in net income (loss) attributable to noncontrolling interest resulting from the change in fair value and lives of tangible assets relating to Independence Hub, L.L.C. Independence Hub, L.L.C., which owns the Independence Hub platform on the Outer Continental Shelf in the Gulf of Mexico, is 80% owned by Enterprise. This change in net income attributable to noncontrolling interest results from the change in net income of Independence Hub, L.L.C. as relating to changes in depreciation expense. These changes in expense are based on fair value and lives of tangible assets of Independence Hub L.L.C. as determined from the preliminary purchase price allocation.

S-38

GENESIS ENERGY, L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(in millions, except where otherwise indicated, or amounts per unit)

(M) Reflects change in common units from the assumed issuance of 9,000,000 million common units at a price of $46.49 per unit (based on a closing price as of July 15, 2015) to finance a portion of this Acquisition. This change in number of common units outstanding and corresponding effects on earnings per unit do not include the effects of Genesis’ April 2015 issuance of common units (for purposes other than this acquisition) which generated net proceeds of approximately $198 million.

S-39

ENTERPRISE OFFSHORE BUSINESS

The Enterprise Offshore Business serves some of the most active drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. The Enterprise Offshore Business includes approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.

Offshore Natural Gas and Crude Oil Pipelines

The offshore Gulf of Mexico pipelines provide for the gathering and transportation of natural gas or crude oil from offshore production fields to interconnecting offshore or onshore pipelines or processing facilities. The results of operations from these pipelines are primarily dependent upon the volume of natural gas or crude oil transported and the level of fees charged to shippers. Transportation fees are based either on contractual arrangements or, as in the case of the High Island Offshore System (“HIOS”), tariffs regulated by the FERC. In general, contractual arrangements for offshore pipeline transportation services tend to be long-term in nature and involve life-of-reserve commitments.

The following table presents selected information regarding the offshore natural gas pipelines at December 31, 2014:


Description of Asset	Ownership Interest			Pipeline Length (Miles)		Approximate Net Capacity (MMcf/d)(1)
Offshore natural gas pipelines:
Independence Trail		100.0	%		135		1,000
Viosca Knoll Gathering System		100.0	%		107		600
High Island Offshore System		100.0	%		287		500
Matagorda Gathering System		100.0	%		127		500
Falcon Natural Gas Pipeline		100.0	%		14		400
Anaconda Gathering System		100.0	%		183		300
Green Canyon Laterals		Variou	s(2)		34		213
Manta Ray Offshore Gathering System		25.7	%(3)		237		205
Nautilus System		25.7	%(3)		101		154

Total					1,225

(1)	Amounts presented are net to the ownership interest of entities owned by the Enterprise Offshore Business in the associated asset.

(2)	The Enterprise Offshore Business proportionately consolidates its undivided interests, which range from 2.7% to 33.3%, in 28 miles of the Green Canyon Lateral pipelines. The remainder of the laterals are wholly owned.

(3)	The Enterprise Offshore Business’s ownership interests in the Manta Ray Offshore Gathering System and the Nautilus System are held indirectly through its equity method investment in Neptune Pipeline Company, L.L.C.

On a weighted-average basis, overall utilization rates for the offshore natural gas pipelines were approximately 12.9%, 14.6% and 12.9% during the years ended December 31, 2014, 2013 and 2012, respectively.

The following information describes each of the principal offshore natural gas pipelines. The Enterprise Offshore Business operates the Independence Trail pipeline, Viosca Knoll Gathering System, High Island Offshore System, Falcon Natural Gas Pipeline, Anaconda Gathering System and certain components of the Green Canyon Laterals. Third parties operate the remainder of the offshore natural gas pipelines.

•

The Independence Trail pipeline transports natural gas from the Independence Hub platform and a pipeline interconnect downstream of the Independence Hub platform to the Tennessee Gas Pipeline at a pipeline interconnect on the West Delta 68 pipeline junction platform. Natural gas transported

S-40

on the Independence Trail pipeline originates from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.

•

The Viosca Knoll Gathering System gathers natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico for delivery to several major interstate pipelines, including the High Point Gas Transmission, Transco, Dauphin Island Gathering System, Tennessee Gas Pipeline and Destin Pipelines.

•

The HIOS transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to interconnects with the TC Offshore system and Kinetica Energy Express. HIOS includes 201 miles of pipeline and eight pipeline junction and service platforms that are regulated by the FERC. In addition, this system includes the 86-mile East Breaks Gathering System, which connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.

•

The Matagorda Gathering System gathers natural gas from producing fields in the Matagorda Island area of the Gulf of Mexico for delivery to interconnecting onshore pipelines located in Matagorda and Calhoun counties in Texas. This system includes two pipeline junction platforms.

•

The Falcon Natural Gas Pipeline transports natural gas processed at the Falcon Nest platform to a connection with the Central Texas Gathering System located at the Brazos Addition Block 133 platform.

•

The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon area of the Gulf of Mexico for delivery to the Nautilus System.

•

The Green Canyon Laterals represent a collection of small diameter pipelines that gather natural gas for delivery to HIOS and various other downstream pipelines.

•

The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to numerous downstream pipelines, including the Nautilus System. This system includes three pipeline junction platforms.

•

The Nautilus System connects the Anaconda Gathering System and Manta Ray Offshore Gathering System to the Neptune natural gas processing plant located in south Louisiana.

The following table presents selected information regarding the Enterprise Offshore Business’s offshore crude oil pipelines at December 31, 2014:


Description of Asset	Ownership Interest			Length (Miles)		Approximate Net Capacity (MBPD)(1)
Offshore crude oil pipelines:
Shenzi Oil Pipeline		100.0	%		83		230
Poseidon Oil Pipeline System		36.0	%(2)		366		155
Cameron Highway Oil Pipeline		50.0	%(3)		374		150
Allegheny Oil Pipeline		100.0	%		40		140
Marco Polo Oil Pipeline		100.0	%		37		120
Constitution Oil Pipeline		100.0	%		67		80
SEKCO Oil Pipeline		50.0	%(4)		145		58
Viosca Knoll Oil Pipeline		100.0	%		6		5
Tarantula		100.0	%		4		30

Total					1,122

(1)	Amounts presented are net to the ownership interest of entities owned by the Enterprise Offshore Business in the associated asset.

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(2)	The Enterprise Offshore Business’s ownership interest in the Poseidon Oil Pipeline System is held indirectly through its equity method investment in Poseidon Oil Pipeline Company, L.L.C.

(3)	The Enterprise Offshore Business’s ownership interest in the Cameron Highway Oil Pipeline is held indirectly through its equity method investment in Cameron Highway Oil Pipeline Company.

(4)	The Enterprise Offshore Business’s ownership interest in the SEKCO Oil Pipeline is held indirectly through its equity method investment in Southeast Keathley Canyon Pipeline Company, L.L.C.

On a weighted-average basis, overall utilization rates for the Enterprise Offshore Business’s offshore crude oil pipelines were approximately 35.9%, 31.3% and 30.6% during the years ended December 31, 2014, 2013 and 2012, respectively.

The following information describes each of the principal offshore crude oil pipelines, all of which the Enterprise Offshore Business operates.

•

The Shenzi Oil Pipeline gathers crude oil production from the Shenzi production field located in the Green Canyon area of the Gulf of Mexico for delivery to both the Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

•

The Poseidon Oil Pipeline System transports crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana to onshore facilities in south Louisiana. This system includes one pipeline junction platform.

•

The Cameron Highway Oil Pipeline transports crude oil production from deepwater areas of the Gulf of Mexico, primarily the Green Canyon area, for delivery to refineries and terminals in southeast Texas. This system includes two pipeline junction platforms.

•

The Allegheny Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with the Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

•

The Marco Polo Oil Pipeline transports crude oil from our Marco Polo oil platform to an interconnect with the Allegheny Oil Pipeline in Green Canyon Block 164.

•

The Constitution Oil Pipeline gathers crude oil from the Constitution, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either the Cameron Highway Oil Pipeline or Poseidon Oil Pipeline System.

•

The SEKCO Oil Pipeline connects the third party-owned Lucius-truss spar floating production platform to an existing junction platform at South Marsh Island 205, which is part of our Poseidon Oil Pipeline System. The SEKCO Oil Pipeline was completed and started earning firm capacity reservation fees in July 2014. Crude oil shipments commenced in January 2015 when the Lucius oil and gas field started operations.

Offshore Hub Platforms

Offshore hub platforms are important components of the Enterprise Offshore Business’s pipeline operations in the Gulf of Mexico. These platforms are typically used to interconnect the offshore pipeline network; provide an efficient means to perform pipeline maintenance; locate compression, separation and production handling equipment and similar assets; and conduct drilling operations during the initial development phase of an oil and natural gas property.

The results of operations from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type fees billable to customers. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform (typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered. Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.

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The following table presents selected information regarding the Enterprise Offshore Business’s offshore hub platforms at December 31, 2014:


Description of Asset	Ownership Interest			Water Depth (Feet)		Approximate Net Capacity(1)
Description of Asset	Ownership Interest			Water Depth (Feet)		Natural Gas (MMcf/d)		Crude Oil (MBPD)
Offshore hub platforms:
Independence Hub		80.0	%(2)		8,000		800		N/A
Marco Polo		50.0	%(3)		4,300		150		60
Viosca Knoll 817		100.0	%		671		145		5
Garden Banks 72		50.0	%(4)		518		113		18
East Cameron 373		100.0	%		441		195		3
Falcon Nest		100.0	%		389		400		3

(1)	Amounts presented are net to the ownership interest.

(2)	The Enterprise Offshore Business owns an 80% consolidated interest in the Independence Hub platform through its majority owned subsidiary, Independence Hub, LLC.

(3)	The Enterprise Offshore Business’s ownership interest in the Marco Polo platform is held indirectly through its equity method investment in Deepwater Gateway, L.L.C.

(4)	The Enterprise Offshore Business proportionately consolidates its undivided interest in the Garden Banks 72 platform.

In addition to the offshore hub platforms, the Enterprise Offshore Business also owns or indirectly owns, through its equity method investees, 17 pipeline junction and service platforms (14 of which it operates). Unlike hub platforms, pipeline junction and service platforms do not have processing capacity.

With respect to natural gas processing capacity, the overall utilization rates (on a weighted-average basis) of the offshore hub platforms were approximately 8.1%, 11.2% and 16.2% during the years ended December 31, 2014, 2013 and 2012, respectively. With respect to crude oil processing capacity, the overall utilization rates (on a weighted-average basis) of the offshore platforms were approximately 16.9%, 17.5% and 18.9% during the years ended December 31, 2014, 2013 and 2012, respectively.

The following information describes each of the Enterprise Offshore Business’s principal Gulf of Mexico offshore hub platforms. The Enterprise Offshore Business operates these platforms with the exception of the Independence Hub and Marco Polo platforms.

•

The Independence Hub platform is located in Mississippi Canyon Block 920. This platform processes natural gas gathered from deepwater production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.

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The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico.

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The Viosca Knoll 817 platform primarily serves as a base for gathering deepwater production in the Viosca Knoll area, including the Ram Powell development.

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The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden Banks area of the Gulf of Mexico. This platform also serves as a junction platform for the Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

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The East Cameron 373 platform processes production from the Garden Banks and East Cameron areas of the Gulf of Mexico.

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The Falcon Nest platform, which is located in the Mustang Island East area of the Gulf of Mexico, processes natural gas from the Falcon field.

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Seasonality

The Enterprise Offshore Business operations exhibit little to no effects of seasonality; however, they may be affected by weather events such as hurricanes and tropical storms in the Gulf of Mexico, which generally arise during the summer and fall months.

Competition

Within their respective market areas, the offshore pipelines compete with other offshore pipelines primarily on the basis of fees charged, available throughput capacity, connections to downstream markets and proximity and access to existing reserves.

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ENTERPRISE OFFSHORE BUSINESS SELECTED FINANCIAL DATA

The selected historical financial data for the Enterprise Offshore Business were derived from the Enterprise Offshore Business’ historical financial statements and the related notes included elsewhere in this prospectus supplement. The selected historical financial data do not purport to project the Enterprise Offshore Business’ results of operations or financial position for any future period or as of any date and are not necessarily indicative of financial results to be achieved in future periods. You should read the selected financial data below together with “Enterprise Offshore Business Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Enterprise Offshore Business’ historical consolidated financial statements and related notes included elsewhere in this prospectus supplement.

The historical consolidated financial data as of December 31, 2014 and 2013 and for the fiscal years ended December 31, 2014, 2013 and 2012 have been audited. The historical consolidated financial statements as of March 31, 2015 and for the three months ended March 31, 2015 and 2014 are unaudited. The Enterprise Offshore Business believes that all material adjustments that consist only of normal recurring adjustments necessary for the fair presentation of its interim results have been included. Results of operations for any interim period are not necessarily indicative of the results of operations for the Enterprise Offshore Business’ entire fiscal year.


	Three months ended March 31,						Year ended December 31,
($ in millions)	2015			2014			2014			2013			2012
Income Statement Data:
Revenues	$	41.1		$	44.4		$	184.4		$	187.9		$	228.3
Costs and expenses		41.7			41.1			180.1			178.7			185.9
Equity in income of unconsolidated affiliates		19.1			11.1			55.2			29.8			26.8
Net income attributable to Enterprise Offshore Business		18.8			14.4			59.9			37.9			64.5
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	53.0		$	39.0		$	175.7		$	149.5		$	173.9
Investing activities		2.2			(2.8	)		13.6			(46.0	)		(72.0	)
Financing activities		(54.5	)		(36.3	)		(189.1	)		(105.4	)		(102.4	)
Balance Sheet Data (at end of period):
Cash and cash equivalents	$	2.7					$	2.0		$	1.8
Total assets		1,765.9						1,796.0			1,920.3
Total liabilities		122.0						117.0			114.2
Total Equity		1,643.9						1,679.0			1,806.1

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ENTERPRISE OFFSHORE BUSINESS

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

Overview of Business

Outlook for 2015

The Enterprise Offshore Business expects that transportation volumes on its offshore crude oil pipelines will continue to increase in the near term as significant deepwater prospects begin production. For example, the SEKCO Oil Pipeline, which serves the Lucius field located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico, commenced operations during the first quarter of 2015. Conversely, the Enterprise Offshore Business expects that throughput volumes on its offshore Gulf of Mexico natural gas pipelines will continue to decline in 2015 due to producers focusing more of their near-term resources to exploit offshore crude oil developments and onshore NGL-rich natural gas and crude oil producing areas; however, increases in natural gas production associated with oil production are expected to temper the overall decline in Gulf of Mexico natural gas production. Development of hydrocarbon reserves in the Gulf of Mexico is capital intensive and projects typically have long lead times. At this time, the Enterprise Offshore Business is uncertain what, if any, effect the current environment of lower hydrocarbon prices will have on producers’ intermediate plans to explore and develop reserves in the Gulf of Mexico.

Three Months Ended March 31, 2015 compared to Three Months Ended March 31, 2014

Results of Operations

The following table summarizes the key components of our results of operations for the three months indicated (dollars in millions):


	For the Three months Ended March 31,
	2015		2014
Revenues	$	41.1	$	44.4
Costs and expenses:
Operating expenses		17.0		17.6
Depreciation, amortization and accretion expense		23.4		21.9
Gain on disposal of fixed assets		—		(0.3	)
General and administrative costs		1.3		1.9

Total costs and expenses		41.7		41.1

Equity in income of unconsolidated affiliates		19.1		11.1

Operating income and net income		18.5		14.4
Net income attributable to noncontrolling interests		0.3		—

Net income attributable to owners	$	18.8	$	14.4

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The following table presents gross operating margin and selected volumetric data for the periods indicated (dollars in millions, volumes as noted):


	Three Months Ended March 31,
	2015		2014
Gross operating margin	$	44.1	$	38.7
Selected volumetric data:
Natural gas transportation volumes (BBtus/d)		619		569
Crude oil transportation volumes (MBPD)		340		335

Comparison of 2015 with 2014

Gross operating margin for the first quarter of 2015 increased $5.4 million when compared to the first quarter of 2014. Gross operating margin for the first quarter of 2015 includes $8.1 million of equity earnings from the Enterprise Offshore Business’ investment in the SEKCO Oil Pipeline, which started earning firm capacity reservation fees in the third quarter of 2014. Aggregate gross operating margin from the Independence Hub platform and Independence Trail pipeline decreased $2.8 million quarter-to-quarter primarily due to lower platform processing and pipeline transportation volumes during the first quarter of 2015.

Years Ended December 31, 2014, December 31, 2013, and December 31, 2012

Results of Operations

The following table summarizes the key components of Enterprise’s Offshore Business results of operations for the years indicated (dollars in millions):


	For the Year Ended December 31,
	2014			2013			2012
Revenues	$	184.4		$	187.9		$	228.3
Costs and expenses:
Operating expenses		84.0			76.0			83.0
Depreciation, amortization and accretion expense		88.4			84.7			90.7
(Gain) loss on disposal of fixed assets		(4.9	)		(2.7	)		0.5
Asset impairment charges		5.1			13.2			4.0
General and administrative costs		7.5			7.5			7.7

Total costs and expenses		180.1			178.7			185.9

Equity in income of unconsolidated affiliates		55.2			29.8			26.8

Operating income and net income		59.5			39.0			69.2
Net loss (income) attributable to noncontrolling interests		0.4			(1.1	)		(4.7	)

Net income attributable to owners	$	59.9		$	37.9		$	64.5

The following table presents gross operating margin and selected volumetric data for the years indicated (dollars in millions, volumes as noted):


	For the Year Ended December 31,
	2014		2013		2012
Gross operating margin	$	159.5	$	144.7	$	174.0
Selected volumetric data:(1)
Natural gas transportation volumes (BBtus/d)		627		678		853
Crude oil transportation volumes (MBPD)		330		307		300

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Year Ended December 31, 2014 compared with Year Ended December 31, 2013

Gross operating margin for 2014 increased $14.8 million when compared to 2013. Gross operating margin for 2014 includes $15.5 million of equity earnings from the Enterprise Offshore Business’ investment in the SEKCO Oil Pipeline, which started earning firm capacity reservation fees in the third quarter of 2014. Equity earnings from the investment in the Cameron Highway Oil Pipeline increased $5.1 million year-to-year primarily due to a 21 MBPD increase (net to our interest) in crude oil transportation volumes. Equity earnings from the investment in Neptune Pipeline Company, L.L.C. (“Neptune”) increased $4.2 million year-to-year primarily due to its 2013 results including a $4.8 million non-cash impairment charge. Lastly, in the aggregate, gross operating margin from the Independence Hub platform and Independence Trail pipeline decreased $15.8 million year-to-year primarily due to lower platform processing and pipeline throughput volumes during 2014. Natural gas processing volumes on the Independence Hub platform decreased 70 MMcf/d year-to-year (net to our interest) and natural gas transportation volumes on the Independence Trail pipeline decreased 81 BBtus/d year-to-year.

Due to the high cost of third party windstorm insurance coverage for the offshore Gulf of Mexico assets, the Enterprise Offshore Business has self-insured these operations since June 2012.

Year Ended December 31, 2013 compared with Year Ended December 31, 2012

Gross operating margin for 2013 decreased $29.3 million when compared to 2012. In the aggregate, gross operating margin from the Independence Hub platform and Independence Trail pipeline decreased $24.7 million year-to-year primarily due to the expiration of contractual platform demand fees during the first quarter of 2012, which accounted for $9.7 million of the decrease, and lower platform processing and pipeline throughput volumes during 2013, which accounted for $16.0 million of the decrease. Natural gas processing volumes on the Independence Hub platform decreased 88 MMcf/d year-to-year (71 MMcf/d net to our interest) and natural gas transportation volumes on the Independence Trail pipeline decreased 73 BBtus/d year-to-year. Gross operating margin from the High Island Offshore System (“HIOS”) decreased $3.4 million year-to-year primarily due to a 37 BBtus/d decrease in natural gas transportation volumes. Equity earnings from our investment in Neptune include a $4.8 million non-cash impairment charge recorded in 2013.

Collectively, gross operating margin from the Shenzi and Constitution Oil Pipelines decreased $7.4 million year-to-year. These pipelines experienced a combined 13 MBPD decrease in throughput volumes primarily due to production declines. Equity earnings from the investment in the Cameron Highway Oil Pipeline increased $7.8 million year-to-year primarily due to a 22 MBPD increase (net to the Enterprise Offshore Business’ interest) in crude oil transportation volumes.

Due to the high cost of third party windstorm insurance coverage for the offshore Gulf of Mexico assets, the Enterprise Offshore Business has self-insured these operations since June 2012. As a result, insurance expense in 2013 decreased $6.5 million when compared to 2012.

Use of Non-GAAP Financial Measure

Management of the Enterprise Offshore Business evaluates the performance of the Enterprise Offshore Business based on the non-GAAP financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of the Enterprise Offshore Business’ operations and forms the basis of the Enterprise Offshore Business’ internal financial reporting. Management of the Enterprise Offshore Business believes that investors benefit from having access to the same financial measures that management uses in evaluating results. The GAAP financial measure most directly comparable to total segment gross operating margin is net income.

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The following table presents a reconciliation of non-GAAP total gross operating margin to GAAP net income for the periods indicated (dollars in millions):


	For the Three Months Ended March 31,						For the Year Ended March 31,
	2015			2014			2014			2013			2012
Gross Operating Margin	$	44.1		$	38.7		$	159.5		$	144.7		$	174.0
Depreciation, Amortization and Accretion		(23.4	)		(21.9	)		(88.4	)		(84.7	)		(90.7	)
General and Administrative Expense		(1.3	)		(1.9	)		(7.5	)		(7.5	)		(7.7	)
Other, net		(0.9	)		(0.5	)		(4.1	)		(13.5	)		(6.4	)

Net Income	$	18.5		$	14.4		$	59.5		$	39.0		$	69.2

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MATERIAL TAX CONSIDERATIONS

The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. For a discussion of certain U.S. federal income tax considerations associated with our operations and the purchase, ownership and disposition of our common units, please read “Material Income Tax Consequences” beginning on page 31 of the accompanying base prospectus. Please also read “Item 1A. Risk Factors — Tax Risks to Common Unitholders” in our Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of the tax risks related to purchasing and owning our common units. You are urged to consult with your own tax advisor about the federal, state, local, and foreign tax consequences specific to your circumstances.

Partnership Status

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.

In rendering its opinion, Akin Gump Strauss Hauer & Feld LLP has relied on factual representations made by us and our general partner, including the following:

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Neither we nor any of our subsidiaries has elected or will elect to be treated as a corporation for U.S. federal income tax purposes;

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For each taxable year, more than 90% of our gross income has been and will be income from sources that Akin Gump Strauss Hauer & Feld LLP has opined or will opine should be “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

•

Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas or products thereof that are held or are to be held by us in activities that Akin Gump Strauss Hauer & Feld LLP has opined or will opine should result in qualifying income.

In order to be treated as a partnership for federal income tax purposes, at least 90% of our gross income must be from specific qualifying sources, such as the transportation, processing or marketing of natural gas and natural gas products or other passive types of income such as dividends. For a more complete description of this qualifying income requirement, please read “Material Income Tax Consequences — Partnership Status” beginning on page 31 of the accompanying base prospectus and “Item 1A. Risk Factors—Tax Risks to Common Unitholders” in our Annual Report on Form 10-K for the year ended December 31, 2014.

No ruling has been or is expected to be sought from the IRS, and the IRS has made no determination, as to our status as a partnership for federal income tax purposes. Instead, we will rely on the opinion of Akin Gump Strauss Hauer & Feld LLP. It is the opinion of Akin Gump Strauss Hauer & Feld LLP that, based upon the Internal Revenue Code, the Treasury Regulations, current administrative rulings and court decisions and the representations described above, we should be classified as a partnership for federal income tax purposes.

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

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Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. On May 5, 2015, the U.S. Treasury Department and the IRS released proposed regulations (the “Proposed Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code. The U.S. Treasury Department and the IRS have requested comments from industry participants regarding the standards set forth in the Proposed Regulations. The Proposed Regulations provide an exclusive list of industry-specific activities and certain limited support activities that generate qualifying income. Although the Proposed Regulations adopt a narrow interpretation of the activities that generate qualifying income, we believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the Proposed Regulations. However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation of Section 7704 of the Code. If the regulations in their final form were to treat any material portion of our income we treat as qualifying income as non-qualifying income, we anticipate being able to treat that income as qualifying income for ten years under special transition rules provided in the Proposed Regulations.

Any modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact an investment in our common units. In addition, 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, we are required to pay Texas franchise tax at a maximum effective rate of 0.5% of our gross income apportioned to Texas.

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 the distribution with respect to the final calendar quarter of 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. This estimate is based upon many assumptions regarding our business and operations, including assumptions as to tariffs, capital expenditures, cash flows, net working capital, and anticipated cash distributions. This estimate and the underlying assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, this estimate is based on current tax law and tax reporting positions that we have adopted. The IRS could disagree with our tax reporting positions, including estimates of the relative fair market values of our assets and the validity of certain allocations. Accordingly, we cannot assure you that the estimate will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than our estimate, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering could be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

•

gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all units; or

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

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Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 20%.

A 3.8% Medicare tax is imposed on certain investment income earned by individuals, estates and trusts. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net income from all investments, and (ii) the amount by which the unitholder’s adjusted gross income exceeds specified thresholds depending on a unitholder’s federal income tax filing status. In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Tax Exempt Organizations and Other Investors

Ownership of common units by tax-exempt entities, regulated investment companies, and non-U.S. investors raises issues unique to such persons. Please read “Material Income Tax Consequences — Tax-Exempt Organizations and Other Investors” beginning on page 40 of the accompanying base prospectus.

Puerto Rico Operations

We conduct a small part of our operations in Puerto Rico. We will file a composite or combined Puerto Rico tax return, as applicable, on behalf of our unitholders and pay taxes due. However, you may be required to file a tax return and pay income taxes in Puerto Rico in certain circumstances as a result of these operations. Based on current law and our estimate of our future operations, we anticipate that Puerto Rico income taxes due will not be material. You are urged to consult your tax advisor on the tax consequences under the laws of Puerto Rico of an investment in our common units.

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UNDERWRITING

We are offering the common units described in this prospectus supplement and the accompanying base prospectus through the underwriters named below. Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Barclays Capital Inc., Credit Suisse Securities (USA) LLC, UBS Securities LLC, Raymond James & Associates, Inc., RBC Capital Markets, LLC and BMO Capital Markets Corp., (collectively, the “Representatives”) are acting as joint book-running managers and representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units listed next to its name in the following table:


Underwriters	Number of Units
Wells Fargo Securities, LLC
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Citigroup Global Markets Inc.
Deutsche Bank Securities Inc.
Barclays Capital Inc.
Credit Suisse Securities (USA) LLC
UBS Securities LLC
Raymond James & Associates, Inc.
RBC Capital Markets, LLC
BMO Capital Markets Corp.
Oppenheimer & Co., Inc.
Robert W. Baird & Co. Incorporated
Janney Montgomery Scott LLC

Total		9,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all of the common units (other than those covered by the underwriters’ option to purchase additional units described below) if they purchase any of the common units.

Option to Purchase Additional Units

We have granted to the underwriters an option, exercisable for up to 30 days from the date of this prospectus supplement, to purchase up to 1,350,000 additional common units at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter must purchase the number of additional common units approximately proportionate to that underwriter’s initial purchase commitment.

Underwriting Discount and Expenses

The underwriters propose to offer some of the common units directly to the public at the public offering price set forth on the cover page of this prospectus supplement and some of the common units to dealers at the public offering price less a concession not to exceed $ per common unit. After the offering, the underwriters may change the public offering price and the other selling terms. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

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The following table shows the underwriting discounts that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.


	No Exercise	Full Exercise
Per unit	$	$
Total	$	$

We estimate that our total expenses of this offering, other than underwriting discounts and commissions, will be approximately $400,000.

Lock-Up Agreements

We, our subsidiaries, our general partner and certain of our affiliates, including certain executive officers and directors of our general partner, have agreed that during the 45 days after the date of this prospectus supplement and subject to certain exceptions, we and they, will not, without the prior written consent of Wells Fargo Securities, LLC, (i) issue, sell, offer to sell, contract or agree to sell, hypothecate, pledge, grant any option to purchase or otherwise dispose of or agree to dispose of, directly or indirectly, or establish or increase a put equivalent position or liquidate or decrease a call equivalent position within the meaning of Section 16 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules and regulations of the SEC promulgated thereunder, with respect to any of our common units or securities convertible into or exchangeable or exercisable for our common units or warrants or other rights to purchase our common units or any other securities of ours that are substantially similar to our common units, (ii) file or cause to become effective a registration statement under the Securities Act of 1933, as amended (the “Securities Act”), relating to the offer and sale of any of our common units or securities convertible into or exchangeable or exercisable for our common units or warrants or other rights to purchase our common units or any other of our securities that are substantially similar to common units, (iii) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of our common units or any securities convertible into or exchangeable or exercisable for our common units or warrants or other rights to purchase our common units or any such securities, whether any such transaction is to be settled by delivery of our common units or such other securities, in cash or otherwise or (iv) publicly announce an intention to effect any transaction specified in clause (i), (ii) or (iii). These restrictions do not apply to, among other things:

•

the sale of common units pursuant to the underwriting agreement;

•

bona fide gifts, provided that the recipient of such common units enters into an agreement to be subject to the same restrictions for the remainder of the 45-day period;

•

dispositions to any trust for the direct or indirect benefit of a signatory to a lock-up agreement or his or her immediately family, provided that such trust enters into an agreement to be subject to the same restrictions for the remainder of the 45-day period;

•

issuances of common units by us upon the exercise of options or warrants or the conversion of Class B Units disclosed as outstanding in this prospectus supplement, the accompanying base prospectus or the documents incorporated by reference herein;

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the issuance of employee unit stock options, phantom units or dividend equivalent rights that are not exercisable or do not vest, as applicable, during the 45-day period pursuant to benefit plans described in this prospectus supplement, the accompanying base prospectus or the documents incorporated by reference herein;

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the deemed issuance or disposition of common units under Section 16 of the Exchange Act upon the cash settlement of phantom units or stock appreciate rights outstanding as of the date of the underwriting agreement;

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•

the filing of a universal shelf registration statement on Form S-3 to register common units or other partnership securities, provided that we shall not issue any common units thereunder until the expiration of the 45-day period;

•

the filing of a registration statement on Form S-8 to register common units under benefit plans disclosed in this prospectus supplement, the accompanying base prospectus or the documents incorporated by reference herein;

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the issuance of common units or other partnership securities in a private placement exempt from registration under the Securities Act, provided that the purchaser of such common units enters into an agreement to be subject to the same restrictions for the remainder of the 45-day period;

•

transfers pursuant to any loan or similar agreement in effect on the date of this prospectus supplement, as amended from time to time, or any successor to any such agreement;

•

the pledge of common units or other partnership securities to secure loans to such persons or entities in connection with any financing transaction to which such persons or entities are parties, provided that such common units or other partnership securities may not be sold or disposed of in connection with the exercise by the lender of any remedies as a secured party until the expiration of the 45-day period;

•

existing pledges pursuant to loan or similar agreements in effect on the date of the underwriting agreement, as amended from time to time, or any successor to any such agreement, or any transfers pursuant to any such agreement; and

•

entering into an equity distribution agreement for an “at the market offering” under Rule 415(a)(4) of the Securities Act and any related filings under the Securities Act or the Exchange Act, including a prospectus supplement and Current Report on Form 8-K, provided that we shall not issue any common units thereunder until the expiration of the 45-day period.

NYSE Listing

Our common units are listed on the NYSE under the symbol “GEL.”

Price Stabilization, Short Positions and Penalty Bids

In connection with the offering, the Representatives, on behalf of the underwriters, may purchase and sell common units in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of common units in excess of the number of common units to be purchased by the underwriters in the offering, which creates a syndicate short position. “Covered” short sales are sales of common units made in an amount up to the number of common units represented by the underwriters’ option to purchase additional common units. In determining the source of common units to close out the covered syndicate short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase units through the option to purchase additional common units. Transactions to close out the covered syndicate short position involve either purchases of the common units in the open market after the distribution has been completed or the exercise of the option to purchase additional common units. The underwriters may also make “naked” short sales of common units in excess of the option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of common units in the open market while the offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the Representatives repurchases common units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

S-55

Any of these activities may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time. Neither we nor the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units.

Certain Relationships

As described in “Use of Proceeds,” some of the net proceeds of the offering by us may be used to repay outstanding borrowings under our revolving credit facility. Because Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., RBC Capital Markets, LLC and BMO Capital Markets Corp. or their respective affiliates are lenders under our revolving credit facility, certain of the underwriters or their affiliates may receive more than 5% of the proceeds of this offering (not including underwriting discounts and commissions). Nonetheless, in accordance with the Financial Industry Regulatory Authority Rule 5121, the appointment of a qualified independent underwriter is not necessary in connection with this offering because the common units offered hereby are interests in a direct participation program. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

The underwriters and their affiliates have provided, or may in the future provide, various investment banking, commercial banking, financial advisory, brokerage and other services to us and our affiliates for which services they have received, and may in the future receive, customary fees and expense reimbursement. The underwriters and their affiliates may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. Citigroup Global Markets Inc. acted as our financial advisor in connection with the Enterprise Offshore Business Acquisition.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers and such investment and securities activities may involve our securities and/or instruments. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Electronic Distribution

This prospectus supplement and the accompanying base prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters. The underwriters may agree to allocate a number of common units for sale to their online brokerage account holders. The common units will be allocated to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than this prospectus supplement and the accompanying base prospectus in electronic format, information contained in any website maintained by an underwriter is not part of this prospectus supplement or the accompanying base prospectus or registration statement of which the accompanying base prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase common units. The underwriters are not responsible for information contained in websites that they do not maintain.

S-56

Indemnification

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Selling Restrictions in Hong Kong

Our common units may not be offered or sold in Hong Kong by means of this prospectus or any other document other than to (a) professional investors as defined in the Securities and Futures Ordinance of Hong Kong (Cap. 571, Laws of Hong Kong) (“SFO”) and any rules made under the SFO or (b) in other circumstances which do not result in this prospectus being deemed to be a “prospectus,” as defined in the Companies Ordinance of Hong Kong (Cap. 32, Laws of Hong Kong) (“CO”), or which do not constitute an offer to the public within the meaning of the CO or the SFO; and no person has issued or had in possession for the purposes of issue, or will issue or has in possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation or document relating to our common units which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to our common units which are or are intended to be disposed of only to persons outside Hong Kong or only to professional investors as defined in the SFO.

Notice to Prospective Investors in Australia

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission (“ASIC”), in relation to the offering. This prospectus supplement does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the “Corporations Act”), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the common units may only be made to persons (the “Exempt Investors”), who are:

(a)

“sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act; and

(b)

“wholesale clients” (within the meaning of section 761G of the Corporations Act),

so that it is lawful to offer the common units without disclosure to investors under Chapters 6D and 7 of the Corporations Act.

The common units applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapters 6D and 7 of the Corporations Act would not be required pursuant to an exemption under both section 708 and Subdivision B of Division 2 of Part 7.9 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapters 6D and 7 of the Corporations Act. Any person acquiring common units must observe such Australian on-sale restrictions.

This prospectus supplement contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus supplement is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

S-57

LEGAL MATTERS

The validity of the common units offered hereby will be passed upon for us by Akin Gump Strauss Hauer & Feld LLP, Houston, Texas. Certain legal matters with respect to the common units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The consolidated financial statements as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, incorporated in this prospectus supplement by reference from Genesis Energy, L.P.’s Current Report on Form 8-K filed July 2, 2015 and the effectiveness of Genesis Energy, L.P. and subsidiaries’ internal control over financial reporting have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein by reference (which report is dual dated and (1) expresses an unqualified opinion and includes an explanatory referring to retrospective adjustments made to reflect updates to Genesis Energy, L.P.’s guarantor subsidiaries and (2) expresses an unqualified opinion on the effectiveness of internal control over financial reporting). Such consolidated financial statements have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The combined financial statements of the Offshore Gulf of Mexico Energy Services Business of Enterprise Products Operating LLC as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014 included and incorporated by reference in this prospectus supplement by reference from Genesis Energy, L.P.’s Current Report on Form 8-K filed with the SEC on July 16 , 2015, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report which is included and incorporated herein by reference. Such financial statements have been so incorporated in reliance upon the report of such firm upon their authority as experts in accounting and auditing.

The financial statements of the Cameron Highway Oil Pipeline Company as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014 incorporated by reference in this prospectus supplement by reference from Genesis Energy, L.P.’s Current Report on Form 8-K filed with the SEC on July 16, 2015, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report which is incorporated herein by reference. Such financial statements have been so incorporated in reliance upon the report of such firm upon their authority as experts in accounting and auditing.

The financial statements of the Poseidon Oil Pipeline Company, L.L.C. as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014 incorporated by reference in this prospectus supplement by reference from Genesis Energy, L.P.’s Current Report on Form 8-K filed with the SEC on July 16, 2015, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report which is incorporated herein by reference. Such financial statements have been so incorporated in reliance upon the report of such firm upon their authority as experts in accounting and auditing.

The financial statements of the Southeast Keathley Canyon Pipeline Company, L.L.C. as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014 incorporated by reference in this prospectus supplement by reference from Genesis Energy, L.P.’s Current Report on Form 8-K filed with the SEC on July 16, 2015, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report which is incorporated herein by reference. Such financial statements have been so incorporated in reliance upon the report of such firm upon their authority as experts in accounting and auditing.

S-58

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

The statements in this prospectus or incorporated by reference into this prospectus that are not historical information may be “forward-looking statements” as defined under federal law.

All statements, other than historical facts, included in this prospectus and the documents incorporated in this prospectus by reference that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, and other such references are forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:

•

demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, NaHS, caustic soda and CO₂, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;

•

throughput levels and rates;

•

changes in, or challenges to, our tariff rates;

•

our ability to successfully identify and close strategic acquisitions, including the Enterprise Offshore Business Acquisition, on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

•

service interruptions in our pipeline transportation systems and processing operations;

•

shutdowns or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum or other products or to whom we sell such products;

•

risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;

•

changes in laws and regulations to which we are subject, including tax withholding issues, accounting pronouncements, and safety, environmental and employment laws and regulations;

•

the effects of production declines and the effects of future laws and government regulation;

•

planned capital expenditures and availability of capital resources to fund capital expenditures;

•

our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our revolving credit facility and the indentures governing our notes, which contain various affirmative and negative covenants;

•

loss of key personnel;

•

cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions at the current level or continue to increase quarterly cash distributions in the future;

S-59

•

an increase in the competition that our operations encounter;

•

cost and availability of insurance;

•

hazards and operating risks that may not be covered fully by insurance;

•

our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flows;

•

changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;

•

natural disasters, accidents or terrorism;

•

changes in the financial condition of customers or counterparties;

•

adverse rulings, judgments, or settlements in litigation or other legal or tax matters;

•

the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and

•

the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors identified in this prospectus under “Risk Factors,” as well as the section entitled “Risk Factors” included in our most recent Annual Report on Form 10-K, our subsequently filed Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and any other prospectus supplement we may file from time to time with the SEC with respect to this offering. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

S-60

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 100 F. Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC’s website at http://www.sec.gov.

The SEC allows us to incorporate by reference information that we file with it. This procedure means that we can disclose important information to you by referring you to documents filed with the SEC. The information that we incorporate by reference is an integral part of this prospectus supplement, and references to this “prospectus supplement” include the documents (or portions of documents) incorporated by reference into this prospectus supplement. Any future filings we make with the SEC prior to the completion of this offering under Section 13(a), 13(c), 14 or 15(d) of the Exchange Act, and which are deemed to be “filed,” are also incorporated by reference in this prospectus supplement. Any statement contained in the filings (or portions of filings) incorporated by reference in this prospectus supplement will be deemed to be modified or superseded for purposes of this prospectus supplement to the extent that a statement contained in this prospectus supplement or in any filing by us with the SEC prior to the completion of this offering modifies, conflicts with or supersedes such statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus supplement. We incorporate by reference, other than information furnished pursuant to Item 2.02 or Item 7.01 of any Current Report on Form 8-K or exhibits filed under Item 9.01 relating to those Items, the documents listed below:

•

Annual Report on Form 10-K for the year ended December 31, 2014;

•

Quarterly Report on Form 10-Q for the quarter ended March 31, 2015; and

•

Current Reports on Form 8-K filed with the SEC on April 10, 2015, May 20, 2015, May 21, 2015, July 2, 2015 (two reports) and July 16, 2015.

You may request a copy of this filing at no cost by making written or telephone requests for copies to:

Investor Relations

Genesis Energy, L.P.

919 Milam, Suite 2100

Houston, Texas 77002

(713) 860-2500

We also make available free of charge on our internet website at http://www genesisenergy.com our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and any amendments to those reports, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this prospectus supplement.

You should rely only on the information incorporated by reference or provided in this prospectus supplement. We have not authorized anyone else to provide you with any information. You should not assume that the information incorporated by reference or provided in this prospectus supplement is accurate as of any date other than the date on the front of each document.

S-61

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

INDEX TO COMBINED FINANCIAL STATEMENTS


	Page No.
Independent Auditors’ Report		F-2

Combined Balance Sheets as of March 31, 2015 (unaudited) and December 31, 2014 and 2013		F-3

Statements of Combined Operations
for the Three Months Ended March 31, 2015 and 2014 (unaudited) and
for the Years Ended December 31, 2014, 2013 and 2012		F-4

Statements of Combined Cash Flows
for the Three Months Ended March 31, 2015 and 2014 (unaudited) and
for the Years Ended December 31, 2014, 2013 and 2012		F-5

Statements of Combined Equity
for the Three Months Ended March 31, 2015 and 2014 (unaudited) and
for the Years Ended December 31, 2014, 2013 and 2012		F-6

Notes to Combined Financial Statements		F-7

F-1

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of Enterprise Products Holdings LLC.

Houston, Texas

We have audited the accompanying combined financial statements of the Offshore Gulf of Mexico Energy Services Business of Enterprise Products Operating LLC (the “Business”), which comprise the combined balance sheets as of December 31, 2014 and 2013, and the related statements of combined operations, cash flows and equity for each of the three years in the period ended December 31, 2014, and the related notes to the combined financial statements.

Management’s Responsibility for the Combined Financial Statements

Management is responsible for the preparation and fair presentation of these combined financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the combined financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Business’ preparation and fair presentation of the combined financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Business’ internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Offshore Gulf of Mexico Energy Services Business as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

As discussed in Note 1 to the combined financial statements, the accompanying combined financial statements have been prepared from the separate records of Enterprise Products Operating LLC. The combined financial statements may not necessarily be indicative of the conditions that would have existed or the results of operations of the Business had been operated as an unaffiliated entity. Our opinion is not modified with respect to this matter.

/s/ Deloitte & Touche LLP

Houston, Texas

July 14, 2015

F-2

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

COMBINED BALANCE SHEETS

(Dollars in millions)


	March 31, 2015		December 31,
	March 31, 2015		2014		2013
		(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	2.7	$	2.0	$	1.8
Accounts receivable — trade, net of allowance for doubtful accounts of $0.9 at March 31, 2015, $0.5 at December 31, 2014 and $0.4 at December 31, 2013		23.9		27.1		24.8
Accounts receivable — related parties		1.0		0.7		1.4
Prepaid expenses		1.6		1.5		1.5
Other current assets		0.5		0.4		1.2

Total current assets		29.7		31.7		30.7
Property, plant and equipment, net (see Note 4)		1,126.0		1,144.5		1,219.5
Investments in unconsolidated affiliates (see Note 5)		487.6		494.9		531.8
Intangible assets (see Note 6)		39.3		41.6		54.7
Goodwill (see Note 2)		82.0		82.0		82.1
Other assets		1.3		1.3		1.5

Total assets	$	1,765.9	$	1,796.0	$	1,920.3

LIABILITIES AND EQUITY
Current liabilities
Accounts payable — trade	$	7.9	$	5.5	$	5.2
Accounts payable — related parties		0.1		—		—
Accrued product payables		1.8		2.0		2.0
Current portion of asset retirement obligations		11.7		12.4		1.6
Deferred revenue		2.8		1.5		2.2
Other current liabilities		0.5		1.0		1.1

Total current liabilities		24.8		22.4		12.1
Noncurrent liabilities		97.2		94.6		102.1
Commitments and contingencies (see Note 9)
Equity (see Note 1)
Owners’ net investment		1,580.8		1,615.2		1,739.2
Noncontrolling interest		63.1		63.8		66.9

Total equity		1,643.9		1,679.0		1,806.1

Total liabilities and equity	$	1,765.9	$	1,796.0	$	1,920.3

The accompanying notes are an integral part of these Combined Financial Statements.

F-3

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

STATEMENTS OF COMBINED OPERATIONS

(Dollars in millions)


	For the Three Months Ended March 31,					For the Year Ended December 31,
	2015		2014			2014			2013			2012
		(Unaudited)		(Unaudited)
Revenues:
Pipeline transportation fees	$	28.5	$	29.2		$	124.4		$	126.2		$	146.9
Platform fees		4.6		5.5			22.8			28.1			48.6
Other revenues		8.0		9.7			37.2			33.6			32.8

Total revenues (see Note 2)		41.1		44.4			184.4			187.9			228.3

Costs and expenses:
Operating expenses		17.0		17.6			84.0			76.0			83.0
Depreciation and accretion expense		21.1		19.3			78.5			73.2			79.9
Amortization of intangible assets		2.3		2.6			9.9			11.5			10.8
Asset impairment charges		—		—			5.1			13.2			4.0
Loss (gain) on disposal of fixed assets		—		(0.3	)		(4.9	)		(2.7	)		0.5
General and administrative costs		1.3		1.9			7.5			7.5			7.7

Total costs and expenses		41.7		41.1			180.1			178.7			185.9

Equity in income of unconsolidated affiliates		19.1		11.1			55.2			29.8			26.8

Operating income and net income		18.5		14.4			59.5			39.0			69.2
Net loss (income) attributable to noncontrolling interest		0.3		—			0.4			(1.1	)		(4.7	)

Net income attributable to owners	$	18.8	$	14.4		$	59.9		$	37.9		$	64.5

The accompanying notes are an integral part of these Combined Financial Statements.

F-4

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

STATEMENTS OF COMBINED CASH FLOWS

(Dollars in millions)


	For the Three Months Ended March 31,						For the Year Ended December 31,
	2015			2014			2014			2013			2012
		(Unaudited)			(Unaudited)
Operating activities:
Net income	$	18.5		$	14.4		$	59.5		$	39.0		$	69.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and accretion expense		21.1			19.3			78.5			73.2			79.9
Amortization of intangible assets		2.3			2.6			9.9			11.5			10.8
Asset impairment charges		—			—			5.1			13.2			4.0
Equity in income of unconsolidated affiliates		(19.1	)		(11.1	)		(55.2	)		(29.8	)		(26.8	)
Distributions from unconsolidated affiliates		26.1			16.7			83.5			61.6			46.7
Loss (gain) on disposition of assets, net		—			(0.3	)		(4.9	)		(2.7	)		0.5
Other noncash items		0.9			0.5			2.5			1.7			1.0
Changes in operating assets and liabilities:
Accounts receivable		2.9			0.1			(1.6	)		4.6			5.9
Other current assets		(0.3	)		(1.8	)		0.8			1.3			(1.0	)
Other assets		0.1			1.5			0.2			(1.5	)		—
Accounts payable		0.8			(2.4	)		(1.1	)		(12.3	)		8.0
Accrued product payables		(0.2	)		(0.4	)		0.1			(0.8	)		0.1
Other current liabilities		(0.1	)		(0.1	)		(1.6	)		(9.3	)		(19.8	)
Noncurrent liabilities		—			—			—			(0.2	)		(4.6	)

Net cash provided by operating activities		53.0			39.0			175.7			149.5			173.9

Investing activities:
Additions to property, plant and equipment		(0.6	)		(0.6	)		(6.4	)		(0.2	)		(0.1	)
Contributions in aid of construction costs		2.6			—			0.4			1.8			0.4
Proceeds from disposition of assets		—			—			12.0			3.2			1.7
Investments in unconsolidated affiliates		(1.8	)		(2.2	)		(5.8	)		(50.8	)		(74.0	)
Return of excess investment in unconsolidated affiliates		2.0			—			13.4			—			—

Net cash provided by (used in) investing activities		2.2			(2.8	)		13.6			(46.0	)		(72.0	)

Financing activities:
Cash distributions to owners, net		(54.1	)		(35.5	)		(186.4	)		(100.7	)		(94.3	)
Cash distributions to noncontrolling interests		(0.4	)		(0.8	)		(2.7	)		(4.7	)		(8.1	)

Net cash used in financing activities		(54.5	)		(36.3	)		(189.1	)		(105.4	)		(102.4	)

Net increase (decrease) in cash		0.7			(0.1	)		0.2			(1.9	)		(0.5	)
Cash, beginning of period		2.0			1.8			1.8			3.7			4.2

Cash, end of period (see Note 1)	$	2.7		$	1.7		$	2.0		$	1.8		$	3.7

The accompanying notes are an integral part of these Combined Financial Statements.

F-5

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

STATEMENTS OF COMBINED EQUITY

(Dollars in millions)


	Owners’ Net Investment			Noncontrolling Interest			Total
Balance, January 1, 2012	$	1,829.1		$	73.9		$	1,903.0
Net income		64.5			4.7			69.2
Cash distributions to owners, net		(94.3	)		—			(94.3	)
Cash distributions to noncontrolling interests		—			(8.1	)		(8.1	)
Other		1.0			—			1.0

Balance, December 31, 2012 (audited)		1,800.3			70.5			1,870.8
Net income		37.9			1.1			39.0
Cash distributions to owners, net		(100.7	)		—			(100.7	)
Cash distributions to noncontrolling interests		—			(4.7	)		(4.7	)
Other		1.7			—			1.7

Balance, December 31, 2013 (audited)		1,739.2			66.9			1,806.1
Net income (loss)		59.9			(0.4	)		59.5
Cash distributions to owners, net		(186.4	)		—			(186.4	)
Cash distributions to noncontrolling interests		—			(2.7	)		(2.7	)
Other		2.5			—			2.5

Balance, December 31, 2014 (audited)		1,615.2			63.8			1,679.0
Net income (loss)		18.8			(0.3	)		18.5
Cash distributions to owners, net		(54.1	)		—			(54.1	)
Cash distributions to noncontrolling interests		—			(0.4	)		(0.4	)
Other		0.9			—			0.9

Balance, March 31, 2015 (unaudited)	$	1,580.8		$	63.1		$	1,643.9


	Owners’ Net Investment			Noncontrolling Interest			Total
Balance, December 31, 2013 (audited)	$	1,739.2		$	66.9		$	1,806.1
Net income		14.4			—			14.4
Cash distributions to owners, net		(35.5	)		—			(35.5	)
Cash distributions to noncontrolling interests		—			(0.8	)		(0.8	)
Other		0.5			—			0.5

Balance, March 31, 2014 (unaudited)	$	1,718.6		$	66.1		$	1,784.7

The accompanying notes are an integral part of these Combined Financial Statements.

F-6

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS

Except as noted in the context of each disclosure, dollar amounts presented in the tabular data

within these disclosures are stated in millions of dollars.

Note 1. Basis of Financial Statement Presentation and Description of Business

Key References Used in these Notes to Combined Financial Statements

Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Business” are intended to mean and include the combined businesses and operations of the Offshore Gulf of Mexico Energy Services Business of Enterprise Products Operating LLC.

References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise Products Partners L.P. (“EPD”), and its consolidated subsidiaries. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates.

As generally used in the energy industry and in these notes to combined financial statements, “MMcf/d” means million cubic feet per day and “MBPD” means thousands of barrels per day.

Basis of Financial Statement Presentation

The accompanying combined financial statements and related notes of the Business have been prepared from EPO’s separate historical accounting records. These combined financial statements have been prepared using EPO’s historical basis in the assets and liabilities of the Business and historical results of operations. The combined financial statements may not necessarily be indicative of the conditions that would have existed or the results of operations of the Business if it had been operated as an unaffiliated entity. See Note 7 for information regarding related party transactions of the Business.

Our combined financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all normal and recurring intercompany accounts and transactions. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests.

Within the energy industry, it is customary for parties to own undivided interests in certain fixed assets rather than structuring a separate legal entity to own the asset and then acquiring equity interests in that company. We proportionately consolidate our undivided interest in such assets. As a result, our combined financial statements reflect our share of the assets, liabilities, revenues and expenses attributable to such fixed assets.

If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In preparing our combined financial statements, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Combined Balance Sheets (or those of our equity method investments) in inventory or similar accounts.

In the opinion of management, all adjustments necessary for a fair presentation of the combined financial statements, in accordance with generally accepted accounting principles (“GAAP”) in the United States of America (“U.S.”), have been made.

F-7

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The combined financial statements as of March 31, 2015 and for the three months ended March 31, 2015 and 2014 are unaudited. In the opinion of management, the unaudited interim combined financial statements have been prepared in accordance with GAAP and include all adjustments necessary to present fairly the financial position and results of operations of the Business for the respective interim periods. Interim financial results are not necessarily indicative of the results to be expected for an annual period.

All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to combined financial statements are unaudited.

Since a single direct owner relationship does not exist among the combined entities, we present our net investment in the entities (i.e., owners’ net investment) in lieu of parent or owners’ equity in the combined financial statements.

With the exception of our Independence Hub, LLC subsidiary (“Independence Hub”), the Business operates within EPO’s cash management program; therefore, all cash receipts and payments of our subsidiaries (excluding Independence Hub) are managed through EPO’s cash accounts. Our Statements of Combined Cash Flows present the operating and investing cash flows of our Business, with any transfers of excess net cash between subsidiaries under EPO’s cash management program and EPO reflected as a distribution to owners. As a result, cash and cash equivalents at the end of each period is attributable solely to balances held by Independence Hub.

Description of the Business

We serve some of the most active drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. As of December 31, 2014, our integrated asset network included approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.

Offshore natural gas pipelines

Our offshore natural gas pipelines provide for the gathering and transportation of natural gas from offshore production fields to interconnecting offshore or onshore pipelines, or processing facilities. The following table presents selected information regarding our offshore natural gas pipelines at December 31, 2014:


Description of Asset	Our Ownership Interest			Pipeline Length (Miles)		Approximate Net Capacity (MMcf/d)(1)
Offshore natural gas pipelines:
Independence Trail		100.0%			135		1,000
Viosca Knoll Gathering System		100.0%			107		600
High Island Offshore System		100.0%			287		500
Matagorda Gathering System(2)		100.0%			127		950
Falcon Natural Gas Pipeline		100.0%			14		400
Anaconda Gathering System		100.0%			183		300
Green Canyon Laterals		Various	(3)		34		213
Manta Ray Offshore Gathering System		25.7%	(4)		237		205
Nautilus System		25.7%	(4)		101		154

Total					1,225

(1)	Amounts presented are net to our ownership interest in the associated asset.

(2)	At March 31, 2015, this system comprised 59 miles of pipeline having an approximate net capacity of 450 MMcf/d.

(3)	We proportionately consolidate our undivided interests, which range from 2.7% to 100.0%, in the Green Canyon Lateral pipelines.

(4)	Our ownership interests in the Manta Ray Offshore Gathering System and the Nautilus System are held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C. (see Note 5).

F-8

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following information describes each of our principal offshore natural gas pipelines.

•

The Independence Trail pipeline transports natural gas from our Independence Hub platform and a pipeline interconnect downstream of our Independence Hub platform to the Tennessee Gas Pipeline at a pipeline interconnect on our West Delta 68 pipeline junction platform. Natural gas transported on the Independence Trail pipeline originates from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.

•

The Viosca Knoll Gathering System gathers natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico for delivery to several major interstate pipelines, including the High Point Gas Transmission, Transco, Dauphin Island Gathering System, Kinetica Energy Express and Destin Pipelines.

•

The High Island Offshore System (“HIOS”) transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to interconnects with the TC Offshore pipeline system and Kinetica Energy Express. HIOS includes 201 miles of pipeline and eight pipeline junction and service platforms that are regulated by the Federal Energy Regulatory Commission (“FERC”). In addition, this system includes the 86-mile East Breaks Gathering System, which connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.

•

The Matagorda Gathering System gathers natural gas from producing fields in the Matagorda Island area of the Gulf of Mexico for delivery to interconnecting onshore pipelines located in Matagorda and Calhoun counties in Texas. This system includes two pipeline junction platforms.

•

The Falcon Natural Gas Pipeline transports natural gas processed at our Falcon Nest platform to a connection with the Central Texas Gathering System located at the Brazos Addition Block 133 platform.

•

The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon area of the Gulf of Mexico for delivery to the Nautilus System.

•

The Green Canyon Laterals represent a collection of small diameter pipelines that gather natural gas for delivery to HIOS and various other downstream pipelines.

•

The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to numerous downstream pipelines, including the Nautilus System. This system includes three pipeline junction platforms.

•

The Nautilus System connects our Anaconda Gathering System and Manta Ray Offshore Gathering System to EPO’s Neptune natural gas processing plant located in south Louisiana.

F-9

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Offshore crude oil pipelines

Our offshore crude oil pipelines provide for the gathering and transportation of crude oil from offshore production fields to interconnecting offshore or onshore pipelines, or processing facilities. The following table presents selected information regarding our offshore crude oil pipelines at December 31, 2014:


Description of Asset	Our Ownership Interest			Length (Miles)		Approximate Net Capacity (MBPD)(1)
Offshore crude oil pipelines:
Shenzi Oil Pipeline		100.0	%		83		230
Poseidon Oil Pipeline System		36.0	%(2)		366		155
Cameron Highway Oil Pipeline		50.0	%(3)		374		150
Allegheny Oil Pipeline		100.0	%		40		140
Marco Polo Oil Pipeline		100.0	%		37		120
Constitution Oil Pipeline		100.0	%		67		80
SEKCO Oil Pipeline		50.0	%(4)		145		58
Tarantula		100.0	%		4		30
Viosca Knoll Oil Pipeline		100.0	%		6		5

Total					1,122

(1)	Amounts presented are net to our ownership interest in the associated asset.

(2)	Our ownership interest in the Poseidon Oil Pipeline System is held indirectly through our equity method investment in Poseidon Oil Pipeline Company, L.L.C. (see Note 5).

(3)	Our ownership interest in the Cameron Highway Oil Pipeline is held indirectly through our equity method investment in Cameron Highway Oil Pipeline Company (see Note 5).

(4)	Our ownership interest in the SEKCO Oil Pipeline is held indirectly through our equity method investment in Southeast Keathley Canyon Pipeline Company, L.L.C. (see Note 5).

The following information describes each of our principal offshore crude oil pipelines.

•

The Shenzi Oil Pipeline gathers crude oil production from the Shenzi production field located in the Green Canyon area of the Gulf of Mexico for delivery to both our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

•

The Poseidon Oil Pipeline System transports crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana to onshore facilities in south Louisiana. This system includes one pipeline junction platform.

•

The Cameron Highway Oil Pipeline transports crude oil production from deepwater areas of the Gulf of Mexico, primarily the Green Canyon area, for delivery to refineries and terminals in southeast Texas. This system includes two pipeline junction platforms.

•

The Allegheny Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

•

The Marco Polo Oil Pipeline transports crude oil from our Marco Polo oil platform to an interconnect with our Allegheny Oil Pipeline in Green Canyon Block 164.

F-10

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

•

The Constitution Oil Pipeline gathers crude oil from the Constitution, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either our Cameron Highway Oil Pipeline or Poseidon Oil Pipeline System.

•

The SEKCO Oil Pipeline connects the third party-owned Lucius-truss spar floating production platform to an existing junction platform at South Marsh Island 205, which is part of our Poseidon Oil Pipeline System. The SEKCO Oil Pipeline was completed and started earning firm capacity reservation fees in July 2014. Crude oil shipments commenced in January 2015 when the Lucius oil and gas field started operations.

Offshore platforms

Offshore hub platforms are important components of our pipeline operations in the Gulf of Mexico. These platforms are typically used to interconnect the offshore pipeline network; provide an efficient means to perform pipeline maintenance; locate compression, separation and production handling equipment and similar assets; and conduct drilling operations during the initial development phase of an oil and natural gas property. The following table presents selected information regarding our offshore hub platforms at December 31, 2014:


						Approximate Net Capacity(1)
Description of Asset	Our Ownership Interest			Water Depth (Feet)		Natural Gas (MMcf/d)		Crude Oil (MBPD)
Offshore hub platforms:
Independence Hub		80.0	%(2)		8,000		800		N/A
Marco Polo		50.0	%(3)		4,300		150		60
Viosca Knoll 817		100.0	%		671		145		5
Garden Banks 72		50.0	%(4)		518		113		18
East Cameron 373		100.0	%		441		195		3
Falcon Nest		100.0	%		389		400		3

(1)	Amounts presented are net to our ownership interest.

(2)	We own an 80% consolidated interest in the Independence Hub platform through our majority owned subsidiary, Independence Hub.

(3)	Our ownership interest in the Marco Polo platform is held indirectly through our equity method investment in Deepwater Gateway, L.L.C. (see Note 5).

(4)	We proportionately consolidate our undivided interest in the Garden Banks 72 platform.

In addition to our offshore hub platforms, we also own or indirectly own, through our equity method investees, 17 pipeline junction and service platforms (14 of which we operate). Unlike hub platforms, pipeline junction and service platforms do not have processing capacity.

The following information describes each of our principal Gulf of Mexico offshore hub platforms.

•

The Independence Hub platform is located in Mississippi Canyon Block 920. This platform processes natural gas gathered from deepwater production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.

•

The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico.

F-11

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

•

The Viosca Knoll 817 platform primarily serves as a base for gathering deepwater production in the Viosca Knoll area, including the Ram Powell development.

•

The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden Banks area of the Gulf of Mexico. This platform also serves as a junction platform for our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

•

The East Cameron 373 platform processes production from the Garden Banks and East Cameron areas of the Gulf of Mexico.

•

The Falcon Nest platform, which is located in the Mustang Island East area of the Gulf of Mexico, processes natural gas from the Falcon field.

Note 2. Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is based on the specific identification of accounts receivable where the underlying amounts due have not been collected within 90 days. In addition, we may also increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and those experiencing other financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Historically, losses attributable to uncollectible accounts have not been material to our combined financial statements.

The following table presents our allowance for doubtful accounts activity for the period indicated:


	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
		(Unaudited)		(Unaudited)
Balance, beginning of period	$	0.5	$	0.4	$	0.4	$	—	$	—
Charged to costs and expenses		0.4		—		0.1		0.4		—

Balance, end of period	$	0.9	$	0.4	$	0.5	$	0.4	$	—

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related property, plant and equipment asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the discounted ARO liability is accreted to its expected settlement value (through “accretion expense”) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

See Note 4 for additional information regarding our AROs.

Cash and cash equivalents

As presented on our Combined Balance Sheets and Statements of Combined Cash Flows, cash and cash equivalents at the end of each period is attributable solely to balances held by Independence Hub.

F-12

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

These balances represent unrestricted cash of Independence Hub and may also include highly liquid investments with original maturities of less than three months from the date of purchase.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us depending on whether one or more future events occur or fail to occur. Management and its legal counsel assess such contingent liabilities on a quarterly basis, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of such matters as well as the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of the liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable, but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, would be disclosed.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the nature of the guarantee would be disclosed.

Current Assets and Current Liabilities

We present, as individual captions on our Combined Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and liabilities, respectively.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. We did not have any environmental remediation liabilities recorded at March 31, 2015 (unaudited) or December 31, 2014 or 2013.

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that effect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.

F-13

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our financial statements.

Equity-Based Compensation

We have no employees. Our operating functions and general and administrative support services are provided pursuant to an administrative services agreement (“ASA”) between EPCO and EPO (see Note 7) or by other service providers. Certain key employees of EPCO that are either wholly or partially dedicated to our Business also participate in long-term compensation plans managed by EPCO. These plans include the issuance of equity-based compensation (e.g., restricted common units of EPD), of which we are charged for our allocated share of the fair value of such awards to the extent that the recipients perform services on our behalf.

The amount of equity-based compensation allocable to our Business was $3.8 million, $3.1 million and $2.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. For the three months ended March 31, 2015 and 2014, the amount of equity-based compensation allocable to our Business was $0.9 million and $0.8 million, respectively (unaudited).

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 3 for information regarding the fair value of financial instruments and nonrecurring fair value measurements.

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in a business combination. The goodwill presented on our Combined Balance Sheets is attributable to a business combination that occurred in 2004. The following table presents changes in the carrying amount of goodwill during the periods indicated:


Balance at January 1, 2012 and December 31, 2012 and 2013	$	82.1
Removal of goodwill in connection with sale of the Typhoon oil pipeline (see Note 4)		(0.1	)

Balance at December 31, 2014	$	82.0

Balance at March 31, 2015 (unaudited)	$	82.0

Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year, and more frequently, if circumstances indicate it is probable that the fair value of goodwill is below its carrying amount. If such circumstances occur, the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its carrying value. If the fair value of the reporting unit is less than its carrying value (including associated goodwill amounts), a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. Our integrated offshore activities comprise a single reporting unit for purposes of goodwill testing. Based on our most recent goodwill impairment test at December 31, 2014, the fair value of our reporting unit exceeded its carrying value by at least 10%.

F-14

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

When testing goodwill for impairment, our fair value estimates are based on a number of management assumptions, including (i) discrete financial forecasts for our offshore assets, including operating margins and throughput volumes; (ii) continuation of existing environmental and safety regulations that allow us to operate our assets in a prudent manner; (iii) tropical weather patterns that do not materially disrupt our operations during the forecast period; (iv) no governmental actions that shut-in Gulf of Mexico production activities (e.g., the moratorium put in place following the third-party Deepwater Horizon incident in 2010); (v) long-term growth rates for cash flows beyond the discrete forecast period; and (vi) appropriate discount rates. We believe that these assumptions are consistent with those that market participants would make in estimating the fair value of our Business.

Impairment Testing for Long-Lived Assets

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.

See Note 3 for information regarding impairment charges related to long-lived assets during the periods covered by this report.

Impairment Testing for Unconsolidated Affiliates

We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. In the event we determine that the loss in value of an investment is an other than temporary decline, we record a charge to equity earnings to adjust the carrying value of the investment to its estimated fair value.

See Note 5 for information regarding a $4.8 million impairment charge we recorded during the year ended December 31, 2013 in connection with our investment in Neptune.

Income Taxes

For federal income tax purposes, our combined operations are considered pass-through entities. As a result, our combined financial statements do not provide for such taxes and our owners are responsible for their allocable share of our taxable income.

Property, Plant and Equipment

Property, plant and equipment is recorded at historical cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period.

F-15

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. Our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management’s assumptions regarding the useful economic lives and residual values of our assets.

Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any.

See Note 4 for additional information regarding our property, plant and equipment.

Revenue Recognition

We recognize revenue from our customers when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectibility is reasonably assured. Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.

Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume gathered or transported multiplied by the volume delivered. Transportation fees are based either on contractual arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered.

Revenues from offshore platform services generally consist of demand fees and commodity charges. Revenues from offshore platform services are recognized in the period the services are provided. Demand fees represent charges to customers served by our offshore platforms regardless of the volume the customer actually delivers to the platform. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform multiplied by the total volume of each product delivered. Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.

Fees we earn through the provision of management or similar services to our unconsolidated affiliates are presented as a component of “Other revenues” on our Statements of Combined Operations.

Major Customer

All of our consolidated revenues are earned in the U.S. and derived from a wide customer base. Our largest non-affiliated customer for the years ended December 31, 2014, 2013 and 2012 was Anadarko. The following table details Anadarko’s contribution to our revenues for the periods indicated:


	For the Year Ended December 31,
	2014			2013			2012
Revenues from Anadarko	$	40.7		$	54.3		$	73.5
Percentage of total revenues attributable to Anadarko		22.1	%		28.9	%		32.1	%

F-16

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Our revenues from Anadarko are primarily due to platform processing and pipeline transportation services we render to them in connection with our Independence Hub platform and related Independence Trail natural gas pipeline.

Subsequent Events

In preparing these combined financial statements, we have evaluated subsequent events for potential recognition or disclosure through July 14, 2015, the issuance date of the financial statements.

Note 3. Fair Value Measurements

Fair Values of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable and accounts payable. The carrying values of accounts receivable and accounts payable approximate their respective fair values due to their short term nature. We do not utilize derivative instruments in our operations.

Fair value is the amount that would be received in an asset sale or paid to transfer a liability in an orderly transaction between unaffiliated market participants. Assets and liabilities measured at fair value are categorized based on whether the inputs are observable in the market and the degree that the inputs are observable. The categorization of financial instruments within the valuation hierarchy is based on the lowest level of input that is significant to the fair value measurement. The hierarchy is prioritized into three levels (with Level 3 being the lowest and most subjective) defined as follows:

•

Level 1: Inputs are based on quoted market prices for identical assets or liabilities in active markets at the measurement date.

•

Level 2: Inputs include quoted prices for similar assets or liabilities in active markets and/or quoted prices for identical or similar assets or liabilities in markets that are not active near the measurement date.

•

Level 3: Inputs include management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. The inputs are unobservable in the market and significant to the valuation.

F-17

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Nonrecurring Fair Value Measurements

We incurred non-cash impairment charges of $5.1 million, $18.0 million and $4.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. There were no non-cash impairment charges incurred for the three months ended March 31, 2015 and 2014, respectively. The following table summarizes our non-recurring fair value measurements during these years:


			Fair Value Measurements Using
	Carrying Value at Respective Year End		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Impairment Loss
Year ended December 31, 2014:
Impairment of long-lived assets disposed of other than by sale(1)	$	—	$	—	$	—	$	—	$	5.1

Year ended December 31, 2013:
Impairment of long-lived assets disposed of other than by sale(2)	$	—	$	—	$	—	$	—	$	13.2
Impairment of equity method investment(3)		38.7		—		—		38.7		4.8

Total	$	38.7	$	—	$	—	$	38.7	$	18.0

Year ended December 31, 2012:
Impairment of long-lived assets disposed of other than by sale(4)	$	—	$	—	$	—	$	—	$	4.0

(1)	Primarily represents the write-off of two segments of pipeline on the Viosca Knoll Gathering System that management slated for abandonment. The carrying value of these assets was $4.8 million.

(2)	Represents the write-off of the northern section of the Phoenix pipeline. The northern section was abandoned and the southern section was contributed to SEKCO (see Note 5).

(3)

Due to declining throughput volumes forecast for these systems in 2014 and future years, we tested our investment in Neptune for impairment in 2013. As a result of this analysis, we recorded a $4.8 million impairment charge. Our fair value estimate for Neptune was based on the income approach, which relies on a discounted cash flow model. The underlying cash flow forecasts we used reflected management’s best estimates regarding future production volumes from the hydrocarbon resource basins served by Neptune and market-based transportation rates (both Level 3 assumptions involving significant unobservable inputs).

(4)	Represents the write-down of certain segments of pipeline on the Anaconda system that were subsequently sold to a third-party in September 2012.

F-18

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Note 4. Property, Plant and Equipment

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:


	Estimated Useful Life in Years		March 31, 2015			December 31,
	Estimated Useful Life in Years		March 31, 2015			2014			2013
				(Unaudited)
Natural gas pipelines and related equipment(1)		5 - 35	$	805.7		$	805.7		$	805.3
Offshore platforms(2)		8 - 35		630.3			630.2			630.1
Crude oil pipelines and related equipment(3)		10 - 35		300.2			300.2			304.8
Other offshore fixed assets(4)		5 - 29		8.7			8.6			8.3
Construction in progress				4.9			5.4			0.4

Total				1,749.8			1,750.1			1,748.9
Less accumulated depreciation				(623.8	)		(605.6	)		(529.4	)

Property, plant and equipment, net			$	1,126.0		$	1,144.5		$	1,219.5

(1)	In general, the estimated useful lives of major assets within this category are: natural gas pipelines, 11-35 years; processing equipment, 14 years; communication equipment, 7-10 years; office furniture and equipment, 10-15 years; vehicles, 5-6 years; and hardware and software, 5 years.

(2)	The largest asset classified within this group, the Independence Hub platform, has a 20 year estimated useful life.

(3)	In general, the estimated useful lives of major assets within this category are: crude oil pipelines, 20-35 years; and communication equipment, 10 years.

(4)	In general, the estimated useful lives of major assets within this category are: underwater pipeline emergency equipment, 29 years; communication equipment, 10 years; and vehicles, 5-6 years.

The following table summarizes our non-cash depreciation expense for each of the periods indicated:


	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
		(Unaudited)		(Unaudited)
Depreciation expense	$	18.2	$	18.1	$	72.7	$	75.4	$	73.6

Contribution of pipeline assets to SEKCO

In 2013, we contributed 47 miles of existing pipeline assets to SEKCO having a carrying value of $33.8 million. See Note 5 for additional information regarding this non-cash contribution to SEKCO.

Sale of Typhoon Oil Pipeline in June 2014

In June 2014, we sold the Typhoon crude oil pipeline for cash proceeds of $12.0 million. As a result, net income for the year ended December 31, 2014 includes a $5.6 million gain from the sale of this asset.

F-19

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Asset retirement obligations

We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. In general, U.S. federal regulations stipulate that energy infrastructure located in the Gulf of Mexico (e.g., pipelines, platforms, production wells, etc.) must be removed when hydrocarbons are no longer being produced. As a practical matter, the agencies overseeing pipeline abandonment activities typically grant approval for operators to remove all hydrocarbons from the pipeline, cut and remove any risers, remove sea valves, fill the pipelines with sea water and abandon the pipeline in-place. With regards to offshore platforms, agencies generally allow operators to abandon in-place the lower portion of platforms with the remaining portion being removed and disposed of. Lastly, agencies require the plugging and abandonment of all offshore oil and gas wells when hydrocarbons are no longer produced.

Certain segments of our pipeline systems and those of our unconsolidated affiliates are constructed in or near defined anchorages, shipping lanes and state waters under permits issued by the U.S. Army Corps of Engineers (the “CoE”). These permits generally require that, upon abandonment of a pipeline segment under the CoE’s jurisdiction, we restore the location to its pre-existing condition. Historically, the CoE has allowed pipeline owners to abandon pipeline segments in-place due to environmental considerations, water depths involved and other factors. Generally, we have assumed, for purpose of determining our ARO liabilities, that the CoE will allow for such pipeline segments to be abandoned in place primarily due to the significant adverse environmental impacts that would result from removal activities and the water depths involved, including deep water Gulf of Mexico locations unless otherwise notified by the CoE.

We have been notified by the CoE to fully remove two pipeline segments included in our Matagorda Gathering System that we had originally requested to abandon in-place. We are in the process of appealing the CoE request. Our ARO liability balance with respect to the Matagorda Gathering System is based on our assessment of the probabilities that we would either (i) be required to fully remove pipeline segments or (ii) be allowed to abandon such segments in place. Our recorded ARO liability balance for the Matagorda Gathering System, including those amounts associated with the potential removal of pipeline segments under the CoE’s jurisdiction, totaled $49.5 million (unaudited), $49.3 million and $47.7 million at March 31, 2015, December 31, 2014 and December 31, 2013, respectively. If we assume the full removal of all impacted pipeline segments of the Matagorda Gathering System, our historical ARO liability balances for this pipeline system would increase by approximately $42.5 million (unaudited), $42.1 million and $40.5 million at March 31, 2015, December 31, 2014 and December 31, 2013, respectively.

The following table presents information regarding our ARO liability balances for the periods indicated:


	For the Three Months Ended March 31,						For the Year Ended December 31,
	2015			2014			2014			2013			2012
		(Unaudited)			(Unaudited)
ARO liability, beginning of period	$	107.0		$	103.7		$	103.7		$	118.1		$	130.2
Liabilities settled		(0.9	)		(0.9	)		(2.5	)		(11.8	)		(26.7	)
Revisions in estimated cash flows		1.6			—			1.0			(7.5	)		9.9
Accretion expense		1.2			1.2			4.8			4.9			4.7

ARO liability, end of period	$	108.9		$	104.0		$	107.0		$	103.7		$	118.1

F-20

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

AROs are measured at their estimated fair value using expected present value techniques. Our estimates of future settlement values for AROs are based on inflation-adjusted asset retirement costs (based on current regulations) expected to be incurred at the end of the expected economic life of the underlying Gulf of Mexico resource basins.

Property, plant and equipment at March 31, 2015 and December 31, 2014 and 2013 includes $11.1 million (unaudited), $11.4 million and $12.4 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

At December 31, 2014, our forecast of accretion expense is as follows for the next five years: $4.8 million in 2015, $4.8 million in 2016, $4.9 million in 2017, $5.0 million in 2018 and $5.3 million in 2019.

Note 5. Investments in Unconsolidated Affiliates

Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

The following table presents the investment balances for each of our unconsolidated affiliates at the dates indicated:


Investee	Ownership Interest			March 31, 2015		December 31,
Investee	Ownership Interest			March 31, 2015		2014		2013
					(Unaudited)
Southeast Keathley Canyon Pipeline Company L.L.C.		50.0	%	$	147.6	$	147.3	$	159.2
Poseidon Oil Pipeline Company, L.L.C.		36.0	%		29.2		31.8		41.7
Cameron Highway Oil Pipeline Company		50.0	%		198.1		201.3		207.7
Deepwater Gateway, L.L.C.		50.0	%		78.9		79.6		84.5
Neptune Pipeline Company, L.L.C.		25.7	%		33.8		34.9		38.7

Total				$	487.6	$	494.9	$	531.8

The following table presents our equity in the income of unconsolidated affiliates for the periods indicated:


Investee	For the Three Months Ended March 31,						For the Year Ended December 31,
	2015			2014			2014			2013			2012
		(Unaudited)			(Unaudited)
Southeast Keathley Canyon Pipeline Company L.L.C.(1)	$	8.1		$	—		$	15.5		$	—		$	—
Poseidon Oil Pipeline Company, L.L.C.		7.0			6.0			23.6			22.1			21.1
Cameron Highway Oil Pipeline Company		4.1			4.7			16.5			11.4			3.6
Deepwater Gateway, L.L.C.		0.3			0.7			1.3			2.1			3.4
Neptune Pipeline Company, L.L.C.		(0.4	)		(0.3	)		(1.7	)		(5.9	)		(1.5	)
Other		—			—			—			0.1			0.2

Total	$	19.1		$	11.1		$	55.2		$	29.8		$	26.8

(1)	Equity earnings commenced when the pipeline was completed in July 2014.

F-21

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following table presents our cash investments in unconsolidated affiliates for the periods indicated:


Investee	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
		(Unaudited)		(Unaudited)
Southeast Keathley Canyon Pipeline Company L.L.C.	$	1.8	$	2.2	$	4.3	$	50.5	$	74.0
Cameron Highway Oil Pipeline Company		—		—		0.5		0.3		—
Other		—		—		1.0		—		—

Total	$	1.8	$	2.2	$	5.8	$	50.8	$	74.0

The following table presents cash distributions received from unconsolidated affiliates for the periods indicated:


Investee	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
		(Unaudited)		(Unaudited)
Southeast Keathley Canyon Pipeline Company L.L.C.	$	7.5	$	—	$	18.3	$	—	$	—
Poseidon Oil Pipeline Company, L.L.C.		9.5		7.6		33.5		27.7		29.3
Cameron Highway Oil Pipeline Company		7.3		6.3		23.3		24.0		6.4
Deepwater Gateway, L.L.C.		1.0		2.0		6.1		7.6		8.1
Neptune Pipeline Company, L.L.C.		0.8		0.8		2.3		2.2		2.7
Other		—		—		—		0.1		0.2

Total	$	26.1	$	16.7	$	83.5	$	61.6	$	46.7

The following tables present summarized aggregate balance sheet and income statement data for our unconsolidated affiliates at the dates and for the periods indicated (on a 100% basis):


	March 31, 2015		December 31,
	March 31, 2015		2014		2013
		(Unaudited)
Balance sheet data:
Current assets	$	45.0	$	42.0	$	67.3
Property, plant and equipment, net		1,293.8		1,311.1		1,346.0
Other assets		2.6		2.9		3.5

Total assets	$	1,341.4	$	1,356.0	$	1,416.8

Current liabilities	$	30.0	$	26.0	$	50.0
Long-term debt		195.3		195.3		183.2
Other liabilities		9.6		9.6		8.9
Equity		1,106.5		1,125.1		1,174.7

Total liabilities and equity	$	1,341.4	$	1,356.0	$	1,416.8

F-22

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
		(Unaudited)		(Unaudited)
Income statement data:
Revenues	$	71.9	$	51.5	$	244.1	$	186.9	$	171.2
Operating income		43.6		28.7		131.9		90.8		73.4
Interest expense		1.2		0.7		3.9		2.7		2.6
Net income		42.5		27.9		127.9		88.1		70.8

Southeast Keathley Canyon Pipeline Company L.L.C.

Southeast Keathley Canyon Pipeline Company L.L.C. (“SEKCO”) is a Delaware limited liability company formed in December 2011 to design, construct, own and operate an unregulated offshore crude oil pipeline system (the “SEKCO Oil Pipeline”) located in the deepwater central Gulf of Mexico. SEKCO is owned 50% by Manta Ray Gathering Company, L.L.C., and indirect wholly owned subsidiary of EPO (“Manta Ray”), and 50% by a subsidiary of Genesis Energy, L.P. (“Genesis”).

The SEKCO Oil Pipeline is a 145-mile, 18-inch diameter crude oil gathering pipeline located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico. The pipeline serves the Lucius production area in southern Keathley Canyon and has a crude oil transportation capacity of 115 thousand barrels per day (unaudited). In addition, the SEKCO Oil Pipeline connects the third-party owned Lucius Spar floating production facility to a junction platform at South Marsh Island 205 that is part of the crude oil pipeline system owned by Poseidon Oil Pipeline Company, L.L.C. Construction of the SEKCO Oil Pipeline was completed in July 2014. EPO managed the construction process and currently serves as operator of the pipeline. Crude oil shipments on the SEKCO Oil Pipeline commenced in January 2015 when the Lucius development started operations.

SEKCO has entered into long-term firm basis pipeline capacity reservation agreements with the Lucius producers. The term of these agreements is 20 years (July 2014 through June 2034), which corresponds to the period of dedicated production from the Lucius producers under the agreements.

Contribution of pipeline assets to SEKCO

In 2013, we contributed 47 miles of existing pipeline assets (the southern section of the Phoenix pipeline) to SEKCO having a carrying value and fair value at the time of the contribution of $33.8 million and $80 million, respectively. Using the straight line method, we are amortizing the $46.2 million gain on the contribution as an increase in equity earnings over a period of 20 years, which is the expected economic life of the contributed asset. Amortization of this gain increased our equity earnings from SEKCO by $0.6 million for the three months ended March 31, 2015 (unaudited) and $1.2 million for the year ended December 31, 2014 (amortization commenced in July 2014).

Poseidon Oil Pipeline Company, L.L.C.

Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) is a Delaware limited liability company formed in February 1996 to design, construct, own and operate an unregulated crude oil pipeline system located in the central Gulf of Mexico offshore Louisiana. Poseidon is owned (i) 36% by Poseidon Pipeline Company, L.L.C. (an indirect wholly owned subsidiary of EPO), (ii) 36% by Equilon Enterprises LLC (d/b/a Shell Oil Products U.S.) and (iii) 28% by a subsidiary of Genesis.

F-23

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The Poseidon Oil Pipeline System (the “Poseidon Pipeline”) gathers crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana for delivery to onshore locations in south Louisiana. The Poseidon Pipeline system extends 366 miles and has an approximate capacity of 430 thousand barrels per day (unaudited). The system includes a pipeline junction platform located at South Marsh Island 205 (“SMI-205”), which connects with the SEKCO Oil Pipeline. Manta Ray serves as operator of the Poseidon Pipeline. Poseidon earns fees from providing crude oil handling services to producers.

At SMI-205, the SEKCO Oil Pipeline interconnects with the Poseidon Pipeline. Like SEKCO, Poseidon has entered into long-term pipeline capacity reservation agreements with the Lucius producers. The term of these agreements is 20 years (July 2014 through June 2034), which corresponds to the period of dedicated production from the Lucius producers under the agreements.

In September 2014, Poseidon completed significant capital projects related to its SMI-205 platform and equipment that it owns on the Ship Shoal 332A platform owned by Manta Ray. These expansion projects were undertaken to support Poseidon’s crude oil handling obligations to the Lucius producers and were financed with operating cash flows and borrowings under Poseidon’s revolving credit facilities.

Poseidon’s revolving credit facilities

Borrowings under Poseidon’s revolving credit facilities are primarily used to fund spending on capital projects. In April 2011, Poseidon entered into a revolving bank credit facility that had an initial borrowing capacity of $125 million, which was increased to $225 million by August 2013. The April 2011 credit facility was terminated when Poseidon entered into its February 2015 revolving credit facility. The principal balance of $186.8 million that was outstanding under the April 2011 credit facility was refinanced under the February 2015 credit facility. The February 2015 credit facility is non-recourse to Poseidon’s owners and secured by its assets.

The February 2015 credit facility contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions to owners. A breach of any of these covenants could result in acceleration of the maturity date of Poseidon’s debt. Poseidon was in compliance with the terms of its credit agreement for all periods presented in these Combined Financial Statements.

Cameron Highway Oil Pipeline Company

Cameron Highway Oil Pipeline Company (“Cameron Highway”) is a Delaware general partnership formed in June 2003 to construct, install, own and operate an unregulated crude oil pipeline system located in the central Gulf of Mexico offshore Texas and Louisiana. Cameron Highway is owned 50% by Cameron Highway Pipeline I, L.P. (an indirect wholly owned subsidiary of EPO) and 50% by subsidiaries of Genesis.

The Cameron Highway pipeline system gathers production from deepwater areas of the central Gulf of Mexico, primarily from the South Green Canyon area, for delivery to markets in southeast Texas. The Cameron Highway system extends 374 miles and has an approximate transportation capacity of 295 thousand barrels per day (unaudited). The system includes pipeline junction platforms located at High Island A5 and Ship Shoal 332B. Manta Ray serves as operator of the Cameron Highway system.

Cameron Highway earns fees from providing crude oil handling services to producers. The Cameron Highway pipeline system is supported by life of lease dedications by certain producers (BP Exploration & Production Inc., BHP Billiton Ltd. (“BHP”), PXP Offshore LLC and Chevron USA Inc.) in the Holstein, Mad Dog and Atlantis fields and by Anadarko Petroleum Corporation (“Anadarko”) with respect to its production from the Constitution and Ticonderoga fields. In addition, Cameron Highway handles crude oil production from the Cottonwood field for Petrobras America Inc. and the Shenzi field for BHP.

F-24

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Deepwater Gateway, L.L.C.

Deepwater Gateway, L.L.C. (“Deepwater Gateway”) is a Delaware limited liability company formed in June 2002 to construct, install and own the Marco Polo tension leg platform and related equipment. Deepwater Gateway is owned 50% by Manta Ray and 50% by Helix Energy Solutions Group, Inc. (“HESG”).

The Marco Polo platform, which is located approximately 180 miles offshore Louisiana in the Gulf of Mexico, is designed to process up to 120 thousand barrels of oil per day and 300 million cubic feet per day of natural gas (unaudited). Deepwater Gateway earns a fee for providing oil and gas processing services to certain producers (the “Marco Polo producers”) in the Marco Polo field (Green Canyon Block 608), Ghengis Khan Field (Green Canyon Block 652) and the K2 Fields (Green Canyon Blocks 518, 562 and 606) under life-of-lease production dedications. The Marco Polo producers include Anadarko, Eni Petroleum US LLC, ConocoPhillips Company, BHP Billiton Petroleum (Deepwater) Inc., MCX Gulf of Mexico, LLC, NIPPON Oil Exploration U.S.A. Limited, Hess Corporation, Repsol E&P USA Inc. and Ecopetrol America Inc.

Anadarko operates the Marco Polo platform and Manta Ray provides us technical and administrative services related to the operation of the platform.

As owners of Deepwater Gateway, Manta Ray and HESG are individually responsible for maintaining insurance coverage on the Marco Polo platform (up to their respective 50% membership interests) with respect to general property damage risks other than damage attributable to named windstorm events. The Marco Polo producers reimburse Deepwater Gateway for the costs of this insurance. In addition, the Marco Polo producers agreed to provide Deepwater Gateway with $392 million of aggregate insurance coverage for named windstorm events through May 2015, which increased to $542 million for the annual policy period beginning in June 2015.

Neptune Pipeline Company, L.L.C.

Neptune Pipeline Company, LLC (“Neptune”) owns a 100% member interest in Manta Ray Offshore Gathering Company, LLC (“MROGC”) and Nautilus Pipeline Company, LLC (“Nautilus”). Neptune was formed in January 1997 to acquire, construct, own and operate the Manta Ray Offshore Gathering System, which is owned by MROGC, and the Nautilus System, which is owned by Nautilus. Neptune is owned 74.33% by Enbridge Offshore Gas Transmission and 25.67% by Sailfish Pipeline Company, LLC, a wholly owned subsidiary of EPO.

The Manta Ray Offshore Gathering System (or “Manta Ray System”) consists of 237 miles of unregulated natural gas gathering pipelines having an approximate transportation capacity of 800 million cubic feet per day (unaudited). The Manta Ray System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to downstream pipelines, including the Nautilus System. The Manta Ray System includes two offshore pipeline junction platforms.

The Nautilus System consists of a 101 mile natural gas pipeline with an approximate transportation capacity of 600 million cubic feet per day (unaudited). The Nautilus System connects the Manta Ray System and EPO’s Anaconda Gathering System to natural gas processing facilities located onshore in south Louisiana.

Revenues from the transportation of natural gas on the Manta Ray System and Nautilus System are recognized upon delivery of natural gas from the pipeline systems. The transportation fees charged by Nautilus are regulated by the FERC.

F-25

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Due to declining throughput volumes forecast for these systems in 2014 and future years attributable to increased competition in the western Walker Ridge area of the Gulf of Mexico, we tested our investment in Neptune for impairment in 2013. As a result of this analysis, we recorded a $4.8 million impairment charge. We believe that our current investment in Neptune is supported by expected future production growth from the eastern Walker Ridge area of the Gulf of Mexico. Enbridge Inc.’s Walker Ridge Gathering System is expected to be placed fully into service during the second quarter of 2015 and serve the Jack St. Malo and Big Foot ultra-deepwater developments of Chevron USA Inc. and Union Oil Company. Volumes gathered by the Walker Ridge Gathering System will be transported to shore using the Manta Ray and Nautilus systems.

Excess Cost

The price we paid to acquire our initial ownership interests in Poseidon and Cameron Highway exceeded our proportionate share of each investee’s net assets. These excess cost amounts are attributable to the fair value of the underlying tangible assets of these entities exceeding their respective book carrying values at the time of our acquisition of ownership interests in these entities. We amortize such excess cost amounts as a reduction to equity earnings in a manner similar to depreciation.

The following table presents the unamortized excess cost amounts for Poseidon and Cameron Highway that are included in the overall investment balance for each investee at the dates indicated:


	March 31, 2015		December 31,
	March 31, 2015		2014		2013
		(Unaudited)
Poseidon	$	7.6	$	7.9	$	8.9
Cameron Highway		1.1		1.1		1.1

Total	$	8.7	$	9.0	$	10.0

Our amortization of excess cost amounts were $1.0 million, $1.3 million and $1.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. Our amortization of excess cost amounts were $0.3 million and $0.2 million for the three months ended March 31, 2015 and 2014, respectively (unaudited). Based on information currently available, we forecast our amortization of excess cost amounts to total $1.1 million in each of the years 2015 through 2019.

Note 6. Intangible Assets

Our identifiable intangible assets primarily consist of customer relationships. These intangible assets represent the estimated economic value we assigned to customer relationships acquired in connection with historical business combinations whereby (i) we acquired information about or access to customers and now have the ability to provide services to them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as service contracts) and through means other than contracts, such as through regular contact by sales or service representatives.

Customer relationship intangible assets are amortized to earnings using a method that closely resembles the pattern in which the economic benefits of the associated offshore hydrocarbon resource basins are expected to be produced. The amortization period for these intangible assets ranges from 11 to 33 years. At December 31, 2014, our forecast of amortization expense is as follows for the next five years: $8.2 million in 2015, $4.7 million in 2016, $4.1 million in 2017, $3.6 million in 2018 and $3.2 million in 2019.

F-26

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following table summarizes our intangible assets at the dates indicated:


	December 31, 2014
	Gross Value		Accumulated Amortization			Carrying Value
Customer relationships	$	195.8	$	(154.9	)	$	40.9
Other		1.2		(0.5	)		0.7

Total	$	197.0	$	(155.4	)	$	41.6


	December 31, 2013
	Gross Value		Accumulated Amortization			Carrying Value
Customer relationships	$	203.9	$	(150.0	)	$	53.9
Other		1.2		(0.4	)		0.8

Total	$	205.1	$	(150.4	)	$	54.7


	March 31, 2015 (Unaudited)
	Gross Value		Accumulated Amortization			Carrying Value
Customer relationships	$	195.8	$	(157.2	)	$	38.6
Other		1.2		(0.5	)		0.7

Total	$	197.0		(157.7	)	$	39.3

The following table presents amortization expense for our intangible assets for the periods indicated:


	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
		(Unaudited)		(Unaudited)
Customer relationships	$	2.3	$	2.6	$	9.8	$	11.4	$	11.2
Other		—		—		0.1		0.1		0.1

Total	$	2.3	$	2.6	$	9.9	$	11.5	$	11.3

Note 7. Related Party Transactions

The following table summarizes our related party revenue and expense transactions for the periods indicated:


	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
		(Unaudited)		(Unaudited)
Revenues:
EPO and affiliates	$	0.3	$	2.2	$	6.2	$	9.1	$	10.2
Unconsolidated affiliates		4.3		5.8		21.4		20.0		19.3

Total	$	4.6	$	8.0	$	27.6	$	29.1	$	29.5

F-27

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


	For the Three Months Ended March 31,				For the Year Ended December 31,
	2015		2014		2014		2013		2012
	(Unaudited)		(Unaudited)
Costs and expenses:
EPO and affiliates	$	4.2	$	5.3	$	19.6	$	19.9	$	19.5
Unconsolidated affiliates		0.3		—		—		0.5		0.2

Total	$	4.5	$	5.3	$	19.6	$	20.4	$	19.7

Related party accounts receivables and accounts payables presented on our Combined Balance Sheets are with our unconsolidated affiliates. We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Allocation of costs from EPO

We have no employees. Our operating functions and general and administrative support services are provided pursuant to the ASA between EPCO and EPO or by other service providers. We are allocated a reasonable portion of the costs incurred by EPO under the ASA based on our use of such services. As it relates to our Business, the significant terms of the ASA are as follows:

•

EPCO provides operating, general and administrative services to EPO at levels necessary to manage and operate our Business in accordance with prudent industry practices. EPCO employs or otherwise retains the personnel that provide these services to us.

•

EPO reimburses EPCO for its services under the ASA in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly and indirectly related to our business or activities (including expenses reasonably allocated to EPO by EPCO).

•

EPO participates as a named insured in EPCO’s overall insurance program, which provides our operations with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. The associated premium expenses are reasonably allocated to us by EPO. See Note 10 for information regarding insurance risks.

Our operating costs and expenses include amounts paid to EPCO for the costs it incurs to operate our Business, including the compensation of EPCO’s employees. Likewise, our general and administrative costs include expenses reasonably allocated to us by EPO for administrative services provided by EPCO under the ASA, including the compensation of EPCO’s employees. In general, our reimbursement to EPO for administrative services is either (i) on an actual basis for direct expenses it incurs on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). With respect to costs allocated to our businesses by EPO, we believe that such allocation is reasonable.

Privately held affiliates of EPCO lease office space to EPO and we are allocated a reasonable share of EPO’s overall cost based on our usage. The rental rates in these lease agreements approximate market rates.

F-28

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Transactions with Unconsolidated Affiliates

Poseidon

We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement (the “Poseidon OMA”). Currently, the Poseidon OMA renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the years ended December 31, 2014, 2013 and 2012 reflect $7.7 million, $5.5 million and $4.1 million, respectively, of fees we earned through the provision of services under the Poseidon OMA. Likewise, our revenues for the three months ended March 31, 2015 and 2014 reflect $2.0 million and $1.9 million, respectively, of such fees (unaudited).

We have space use rights on the SS-332B offshore platform owned by Cameron Highway. This platform is located adjacent to our SS-332A offshore platform. We sublease our space on SS-332B to Poseidon and also lease space on SS-332A to Poseidon. The term of these agreements extend until the platforms are abandoned. Our revenues for each of the years ended December 31, 2014, 2013 and 2012 reflect $0.3 million of fees we earned under these leasing arrangements. Likewise, our revenues for both of the three months ended March 31, 2015 and 2014 reflect $0.1 million of such fees (unaudited).

Cameron Highway

We provide management, administrative and pipeline operator services to Cameron Highway under an Operation and Management Agreement (the “Cameron Highway OMA”). The Cameron Highway OMA renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the years ended December 31, 2014, 2013 and 2012 reflect $6.4 million, $6.3 million and $5.8 million, respectively, of fees we earned through the provision of services under the Cameron Highway OMA. Likewise, our revenues for both of the three months ended March 31, 2015 and 2014 reflect $1.6 million of such fees (unaudited).

Cameron Highway also leases space on our Garden Banks 72 offshore platform. We received $0.8 million, $0.7 million and $0.7 million in lease payments from Cameron Highway during the years ended December 31, 2014, 2013 and 2012, respectively. Likewise, we received $0.2 million and $0.1 million in lease payments from Cameron Highway during the three months ended March 31, 2015 and 2014, respectively (unaudited).

We lease space on Cameron Highway’s SS-332B offshore platform. We paid $0.1 million in lease payments to Cameron Highway during each of the years ended December 31, 2014, 2013 and 2012. Our lease payments to Cameron Highway during the three months ended March 31, 2015 and 2014 were less than $0.1 million in each interim period (unaudited).

Deepwater Gateway

We provide technical and administrative services to Deepwater Gateway under a Management Services Agreement (the “Deepwater Gateway MSA”). The Deepwater Gateway MSA continues indefinitely until either party decides to exercise their termination rights (as defined in the agreement). Our revenues for each of the years ended December 31, 2014, 2013 and 2012 reflect $0.1 million of fees we earned through the provision of services under the Deepwater Gateway MSA. Likewise, our revenues for both of the three months ended March 31, 2015 and 2014 reflect $34 thousand of such fees (unaudited).

F-29

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

SEKCO

We provide project and asset management, administrative and pipeline operator services to SEKCO under an Operating and Management Agreement (the “SEKCO OMA”). The SEKCO OMA began in July 2014 upon completion of the SEKCO Oil Pipeline. The SEKCO OMA continues indefinitely until either party decides to exercise their termination rights (as defined in the agreement). Our revenues for the year ended December 31, 2014 reflects $0.3 million of fees we earned through the provision of services under the SEKCO OMA. Likewise, our revenues for the three months ended March 31, 2015 reflect $0.2 million of such fees, respectively (unaudited).

Note 8. Commitments and Contingencies

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings.

Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of any contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our combined financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to establish reserves for litigation losses. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court.

We do not have any current or pending litigation involving our offshore operations that is expected to have a material impact on our combined financial statements. Accordingly, we did not establish any reserves for litigation at March 31, 2015 or December 31, 2014 or 2013.

Independence Hub Agreement

In November 2004, we entered into the Independence Hub Agreement (the “IHA”) with a group of producers (the “I-Hub Producers”) currently consisting of Anadarko, Marubeni Oil and Gas USA Inc., Statoil Gulf of Mexico LLC, Eni Petroleum Co. Inc. and Energy Resource Technology GOM, Inc. The I-Hub Producers committed to us for processing their natural gas production from certain oil and gas leases (life of lease production dedications) located in the Atwater Valley, DeSoto Canyon, Mississippi Canyon and Lloyd Ridge areas of the Gulf of Mexico.

F-30

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

In turn, we are required to reserve sufficient processing capacity, as detailed in the IHA, on the Independence Hub platform to handle such dedicated production. To the extent we have excess platform processing capacity (i.e., capacity not reserved by the I-Hub Producers), we may seek additional customers to utilize such spare capacity.

The I-Hub Producers pay their allocable share of all operating and maintenance costs of the platform based on throughput volumes. Such costs are paid directly to Anadarko, as operator of the platform.

Excluding force majeure situations, an I-Hub Producer may terminate its relationship with us under the IHA if we fail to process such producer’s production for 45 consecutive days, or 90 days in any 365-day period. If an I-Hub Producer relinquishes its dedicated leases, the IHA terminates with respect to that producer.

Contractual Obligations

HIOS has entered into a separation, dehydration and measurement services agreement with a third-party service provider. This agreement obligates HIOS to pay $0.2 million per month through the remainder of 2015. We have no other material contractual obligations.

Noncurrent Liabilities

The following table summarizes the components of “Noncurrent liabilities” as presented on our Combined Balance Sheets at the dates indicated:


	March 31, 2015		December 31,
	March 31, 2015		2014		2013
		(Unaudited)
Long-term portion of asset retirement obligations (see Note 4)	$	97.2	$	94.6	$	102.1

Note 9. Significant Risks and Uncertainties

Nature of Operations in the Gulf of Mexico

We provide midstream energy services to producers in the Gulf of Mexico. Our services include the gathering, transporting, platform processing or otherwise handling of crude oil and natural gas volumes for customers. Demand for our services depends on crude oil and natural gas production volumes from the resource basins served by our assets. Changes in the prices of crude oil and natural gas may impact upstream production activities and downstream demand for hydrocarbon products. Production volumes may be negatively impacted by decreases in crude oil and natural gas prices to the extent that such price declines render the associated production wells uneconomic, which would result in production being shut-in. Changes in the prices of crude oil and natural gas may also impact demand for hydrocarbon products, which in turn may impact production volumes. Decreases in demand may be caused by a variety of factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition from other forms of energy, adverse weather conditions and government regulations affecting hydrocarbon prices and production levels.

Our offshore pipelines and platforms are directly impacted by producer exploration and production activities in the Gulf of Mexico for crude oil and natural gas. These reserves are depleting assets. Our pipeline systems must access additional reserves to offset either (i) the natural decline in production from

F-31

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

existing connected wells and/or (ii) the loss of production to competing service providers. We actively seek to offset the loss of volumes due to depletion by adding connections to new customers and production fields.

Offshore exploration and production activities involve additional risks and different regulations than similar activities in onshore developments. Since the Deepwater Horizon (or Macondo) oil spill in the Gulf of Mexico during 2010, an event unrelated to our operations, the U.S. federal government and state regulatory authorities have promulgated substantial additional regulations, including regulations related to the approval of new permits for offshore drilling, enhanced inspections of offshore oil and gas rigs and more stringent safety and accident preparedness plans. These new regulatory requirements have added, and may continue to add, delays in the permitting of offshore wells and costs in the planning, permitting, development and operation of new and existing wells by our customers. A decline in, or failure to achieve anticipated volumes of crude oil and natural gas supplies due to any of these factors could have a material adverse effect on our financial position, results of operations and cash flows. In addition, to the extent that new regulations or other governmental actions significantly increase the estimated future costs associated with our asset retirement obligations, it could have a material adverse effect on our financial position, results of operations or cash flows.

Our assets are located in the northern Gulf of Mexico primarily offshore Texas, Louisiana, Mississippi and Alabama and may suffer damage and resulting downtime due to tropical weather events such as hurricanes. If our assets, or those connected to our assets (e.g., a downstream pipeline or platform), were to experience significant weather-related losses and downtime, it could have a material impact on our financial position, results of operations and cash flows. See “Insurance Risks” below.

Insurance Risks

Under the EPCO ASA (see Note 7), EPO participates as a named insured in EPCO’s overall insurance program, which provides our operations with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our offshore operations. While we believe EPCO maintains adequate insurance coverage on behalf of EPO, insurance may not fully cover every type of damage, interruption or other loss that might occur. If our offshore operations were to incur a significant loss for which EPO was not fully insured, it could have a material impact on our combined financial position, results of operations and cash flows.

In addition, there may be timing differences between amounts we recognize related to property damage costs, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our combined operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our owners.

Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to an explosion and fire or named windstorm). Certain of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are immediately expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired asset(s).

F-32

OFFSHORE GULF OF MEXICO ENERGY SERVICES BUSINESS

OF ENTERPRISE PRODUCTS OPERATING LLC

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Combined Balance Sheets and presented as capital expenditures on our Statements of Combined Cash Flows.

Currently, EPCO’s deductible for non-windstorm related property damage claims involving our offshore assets is $5.0 million. We continue to maintain business interruption coverage for our offshore assets, except for those situations involving windstorm-related downtime. Due to the high cost of windstorm insurance coverage for our offshore Gulf of Mexico assets, we elected to self-insure these assets beginning in June 2013. We have continued to self-insure these assets for the annual policy period ending in May 2016.

Although EPCO’s current insurance program does not provide any windstorm coverage for our offshore assets, producers affiliated with our Independence Hub and Marco Polo platforms continue to provide certain levels of physical damage windstorm coverage for each of these offshore assets. The Independence Hub and Marco Polo producers agreed to provide us with $545 million and $392 million, respectively, of aggregate insurance coverage for named windstorm events through May 2015. With respect to the policy period beginning in June 2015, we expect the Independence Hub and Marco Polo producers to provide us with $545 million and $542 million, respectively, of aggregate insurance coverage for named windstorm events through May 2016.

F-33

Prospectus

LOGO

GENESIS ENERGY, L.P.

Common Units

Preferred Securities

Subordinated Securities

Options

Warrants

Rights

Debt Securities

GENESIS ENERGY FINANCE CORPORATION

Debt Securities

We may from time to time offer one or more classes or series of the following securities as described in this prospectus, in one or more separate offerings under this prospectus:

•

common units, preferred securities, subordinated securities, options, warrants and rights; and

•

debt securities, which may be either senior debt securities or subordinated debt securities.

Genesis Energy Finance Corporation may act as co-issuer of the debt securities and other direct or indirect subsidiaries of Genesis Energy, L.P., other than “minor” subsidiaries as such item is interpreted in securities regulations governing financial reporting for guarantors, may guarantee the debt securities.

This prospectus provides you with the general terms of these securities and the general manner in which we will offer these securities. We may offer and sell securities using this prospectus only if it is accompanied by a prospectus supplement. We will include the specific terms of any securities we offer in a prospectus supplement. The prospectus supplement will also describe the specific manner in which we will offer the securities. You should read this prospectus and the prospectus supplement carefully.

We may sell these securities to underwriters or dealers, or we may sell them directly to other purchasers. See “Plan of Distribution.” The prospectus supplement will list any underwriters and the compensation they will receive. The prospectus supplement will also show you the total amount of money that we will receive from selling these securities, after we pay certain expenses of the offering.

Our common units are listed on the New York Stock Exchange under the symbol “GEL.” We will provide information in any applicable prospectus supplement regarding the trading market, if any, for any debt securities we may offer.

Investing in our securities involves risks. Limited partnerships are inherently different from corporations. You should carefully consider the Risk Factors beginning on page 2 of this prospectus and contained in any applicable prospectus supplement and in the documents incorporated by reference herein and therein before you make an investment in our securities.

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

The date of this prospectus is April 6, 2015.

TABLE OF CONTENTS


ABOUT THIS PROSPECTUS			1
GENESIS ENERGY, L.P.			1
RISK FACTORS			2
USE OF PROCEEDS			2
RATIO OF EARNINGS TO FIXED CHARGES			3
DESCRIPTION OF OUR EQUITY SECURITIES			4
General			4
Our Common Units			4
Our Preferred Securities			7
Our Subordinated Securities			8
Our Options			8
Our Warrants			9
Our Rights			10
CASH DISTRIBUTION POLICY			12
Distributions of Available Cash			12
Adjustment of Quarterly Distribution Amounts			12
Distributions of Cash Upon Liquidation			12
DESCRIPTION OF OUR PARTNERSHIP AGREEMENT			13
Partnership Purpose			13
Power of Attorney			13
Reimbursements of Our General Partner			13
Issuance of Additional Securities			13
Amendments to Our Partnership Agreement			13
Withdrawal or Removal of Our General Partner			14
Liquidation and Distribution of Proceeds			14
Change of Management Provisions			15
Limited Call Right			15
Indemnification			15
DESCRIPTION OF DEBT SECURITIES AND GUARANTEES			16
General			16
Indentures			16
Series of Debt Securities			17
Amounts of Issuances			17
Principal Amount, Stated Maturity and Maturity			17
Specific Terms of Debt Securities			18
Governing Law			19
Form of Debt Securities			19
Redemption or Repayment			22
Mergers and Similar Transactions			23
Subordination Provisions			23
Defeasance, Covenant Defeasance and Satisfaction and Discharge			25
No Personal Liability			25
Default, Remedies and Waiver of Default			26
Modifications and Waivers			27
Special Rules for Action by Holders			29
Form, Exchange and Transfer			30
Payments			31
Guarantees			31
Paying Agents			32
Notices			33
Our Relationship With the Trustee			33
Warrants to Purchase Debt Securities			33


MATERIAL INCOME TAX CONSEQUENCES			35
Partnership Status			35
Limited Partner Status			37
Tax Consequences of Unit Ownership			38
Tax Treatment of Operations			42
Disposition of Common Units			43
Uniformity of Units			45
Tax-Exempt Organizations and Other Investors			46
Administrative Matters			47
State, Local, Foreign and Other Tax Consequences			49
INVESTMENT IN GENESIS BY EMPLOYEE BENEFIT PLANS			50
PLAN OF DISTRIBUTION			53
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS			55
LEGAL MATTERS			57
EXPERTS			57
WHERE YOU CAN FIND MORE INFORMATION			58

ABOUT THIS PROSPECTUS

This prospectus, including any information incorporated by reference herein, is part of a registration statement on Form S-3 that we have filed with the Securities and Exchange Commission, or the Commission, using a “shelf” registration or continuous offering process. Under this shelf registration process, we may, from time to time, offer and sell any combination of the securities described in this prospectus in one or more offerings. This prospectus generally describes Genesis Energy, L.P. and the securities. Each time we sell securities with this prospectus, we will provide a prospectus supplement containing specific information about the terms of a particular offering. A prospectus supplement may also add to, update or change information in this prospectus. You should read carefully the section entitled “Information Regarding Forward-Looking Statements” beginning on page 55. If the description of the offering varies between the prospectus supplement and this prospectus, you should rely on the information in the prospectus supplement. Therefore, you should carefully read both this prospectus and any prospectus supplement, together with additional information described under the heading “Where You Can Find More Information” before you invest in our securities.

You should rely only on the information contained in this prospectus, any prospectus supplement and the documents we have incorporated by reference. We have not authorized anyone else to provide you different information. We are not making an offer of these securities in any state where the offer is not permitted. We will disclose any material changes in our affairs in an amendment to this prospectus, a prospectus supplement or a future filing with the Commission incorporated by reference in this prospectus and any prospectus supplement. You should not assume that the information in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of those documents.

Unless the context otherwise requires, references in this prospectus to “Genesis Energy, L.P.,” “Genesis,” “we,” “our,” “us” or like terms refer to Genesis Energy, L.P. and its operating subsidiaries, including Genesis Energy Finance Corporation; “our general partner” refers to Genesis Energy, LLC, the general partner of Genesis; “CO2” means carbon dioxide; and “NaHS,” which is commonly pronounced as “nash,” means sodium hydrosulfide.

GENESIS ENERGY, L.P.

For additional information regarding our business properties and financial condition, please refer to the documents referenced in the section entitled “Where You Can Find More Information.”

RISK FACTORS

An investment in our securities involves risks. In evaluating an investment in our securities, you should consider carefully the risk factors and other information included in or incorporated by reference into this prospectus and additional information which may be incorporated by reference into this prospectus or any prospectus supplement in the future, in each case as provided under “Where You Can Find More Information,” including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, including the risk factors described under “Risk Factors” in such reports. In addition, when we offer and sell any securities pursuant to a prospectus supplement, we may include additional risk factors relevant to such securities in the prospectus supplement. This prospectus also contains forward-looking statements that involve risks and uncertainties. If any of these risks occur, our business, financial condition or results of operation could be adversely affected. Please read “Information Regarding Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors.

USE OF PROCEEDS

Unless otherwise specified in an accompanying prospectus supplement, we will use the net proceeds we receive from the sale of the securities described in this prospectus for general partnership purposes, which may include, among other things, repayment of indebtedness, the acquisition of businesses and other capital expenditures, payment of distributions and additions to working capital. The exact amounts to be used and when the net proceeds will be applied will depend on a number of factors, including our funding requirements and the availability of alternative funding sources.

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the periods indicated:


	Year Ended December 31,
	2014		2013		2012		2011		2010
Ratio of earnings to fixed charges		2.4		2.4		3.2		2.7		—	(1)

(1)	Earnings were inadequate to cover fixed charges for the year ended December 31, 2010 by $43,640,000.

For the purpose of computing the ratio of earnings to fixed charges, earnings are comprised of income from continuing operations of consolidated subsidiaries before provision for income taxes and adjustment for non-controlling interests in consolidated subsidiaries or income or loss from equity investees, less capitalized interest, plus depreciation of capitalized interest, dividends from companies accounted for using the equity method, and fixed charges. Fixed charges are comprised of interest on long-term debt plus capitalized interest, amortization of capitalized costs related to indebtedness, and rental expense representative of an interest factor.

DESCRIPTION OF OUR EQUITY SECURITIES

General

As of the date of this prospectus, we have outstanding only common units. In the future, we may issue one or more series or classes of additional common units as well as the following other types of equity securities — preferred securities, subordinated securities, options securities, warrant securities or rights securities. Those equity securities may have rights to distributions and allocations junior, equal or superior to our common units. Our general partner can determine the voting powers, designations, preferences and relative, participating, optional or other special rights, duties and qualifications, limitations or restrictions of any series or class and the number constituting any series or class of equity securities.

Our Common Units

Our common units represent limited partner interests in Genesis Energy, L.P. that entitle the holders to participate in our cash distributions and to exercise the rights or privileges available to limited partners under our partnership agreement.

Our outstanding common units are listed on the New York Stock Exchange under the symbol “GEL.”

The transfer agent and registrar for our common units is American Stock Transfer & Trust Company.

Status as Limited Partner or Assignee. Except as described under “— Limited Liability,” the common units will be fully paid, and the unitholders will not be required to make additional capital contributions to us.

Transfer of Common Units. Each purchaser of common units offered by this prospectus must execute a transfer application. By executing and delivering a transfer application, the purchaser of common units:

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becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

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automatically requests admission as a substituted limited partner in our partnership;

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agrees to be bound by the terms and conditions of, and executes, our partnership agreement;

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represents that he has the capacity, power and authority to enter into the partnership agreement;

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grants powers of attorney to officers of our general partner and any liquidator of our partnership as specified in the partnership agreement; and

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makes the consents and waivers contained in the partnership agreement.

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. Our general partner may withhold its consent in its sole discretion.

Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the purchased common units. A purchaser of common units who does not execute and deliver a transfer application obtains only:

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the right to assign the common unit to a purchaser or transferee; and

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the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased common units.

Thus, a purchaser of common units who does not execute and deliver a transfer application:

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will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and

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may not receive some federal income tax information or reports furnished to record holders of common units.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Limited Liability. Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:

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to remove or replace our general partner;

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to approve some amendments to our partnership agreement; or

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to take other action under our partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under Delaware law, to the same extent as our general partner. This liability would extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of our partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to our partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and which could not be ascertained from our partnership agreement.

Meetings; Voting. Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed and which are entitled to vote thereat. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in our partnership, although additional limited partner interests having special voting rights could be issued. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates or a person or group who acquires the units with the prior approval of the board of directors, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, the person or group will lose voting rights on any matter relating to the succession, election, removal, withdrawal, replacement or substitution of our general partner and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes if the matter to be voted on relates to the succession, election, removal, withdrawal, replacement or substitution of our general partner. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Books and Reports. Our general partner is required to keep appropriate books of our business at our principal office. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 75 days after the close of each fiscal year (or such shorter period as the Commission may prescribe), an annual report containing audited financial statements and a report on those financial statements by our registered independent public accountants. Except for our fourth quarter, we will also furnish or make available unaudited financial information within 40 days after the close of each quarter (or such shorter period as the Commission may prescribe).

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

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a current list of the name and last known address of each partner;

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a copy of our tax returns;

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information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

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copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

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information regarding the status of our business and financial condition; and

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any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.

Class B Units. Unless the context otherwise requires, references to common units in this prospectus refer to “Common Units — Class A” under our partnership agreement, which are traditional common units. Our partnership agreement also provides for common units designated “Common Units — Class B,” or Class B Units. The Class B Units are identical to the Class A Units and, accordingly, have voting and distribution rights equivalent to those of the Class A Units, except, in addition, Class B Units have the right to elect all of our board of directors (subject to the right of members of the Davison family, including James E. Davison, James E. Davison, Jr., Steven K. Davison and Todd A. Davison, and their affiliates to elect up to three directors under certain terms pursuant to a unitholders rights agreement). If members of the Davison family and their affiliates own (i) 15% or more of our common units, they have the right to appoint three directors, (ii) less than 15% but more than 10%, they have the right to appoint two directors, and (iii) less than 10%, they have the right to appoint one director. The Class B Units are convertible into Class A Units at the option of the holders or in the event that the holders of at least a majority of the common units (excluding such units held by affiliates of our general partner) replace the existing general partner with a successor general partner or otherwise remove Class B Units’ right to elect our board of directors. The transfer agent for the Class B Units is our general partner.

Summary of Partnership Agreement. For a summary of the important provisions of our partnership agreement, many of which apply to holders of common units, see “Description of Our Partnership Agreement” in this prospectus.

Our Preferred Securities

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for the consideration and with the designations, rights, preferences, and privileges established by our general partner without the approval of any of our limited partners. In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that have certain preferential rights to which our common units are not entitled, including, without limitation, preferences regarding voting and distributions. As of the date of this prospectus, we have no preferred securities outstanding.

Should we offer preferred securities under this prospectus, a prospectus supplement relating to the particular series of preferred securities offered will include the specific terms of those preferred securities, including, among other things, the following:

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the designation, stated value, and liquidation preference of the preferred securities and the number of preferred securities offered;

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the initial public offering price at which the preferred securities will be issued;

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the conversion or exchange provisions of the preferred securities;

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any redemption or sinking fund provisions of the preferred securities;

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the distribution rights of the preferred securities, if any;

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a discussion of any additional material federal income tax considerations (other than as discussed in this prospectus), if any, regarding the preferred securities; and

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any additional rights, preferences, privileges, limitations, and restrictions of the preferred securities.

The transfer agent, registrar, and distributions disbursement agent for the preferred securities will be designated in the applicable prospectus supplement.

Our Subordinated Securities

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for the consideration and with the designations, rights, preferences, and privileges established by our general partner without the approval of any of our limited partners. In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that have certain rights, including, without limitation, rights regarding voting and distributions, subordinate to the rights of our common units or preferred securities. As of the date of this prospectus, we have no subordinated securities outstanding.

Should we offer subordinated securities under this prospectus, a prospectus supplement relating to the particular series of subordinated securities offered will include the specific terms of those subordinated securities, including, among other things, the following:

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the designation, stated value, and liquidation rights of the subordinated securities and the number of subordinated securities offered;

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the initial public offering price at which the subordinated securities will be issued;

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the conversion or exchange provisions of the subordinated securities;

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any redemption or sinking fund provisions of the subordinated securities;

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the distribution rights of the subordinated securities, if any;

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a discussion of any additional material federal income tax considerations (other than as discussed in this prospectus), if any, regarding the subordinated securities; and

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any additional rights, limitations, and restrictions of the subordinated securities.

The transfer agent, registrar, and distributions disbursement agent for the subordinated securities will be designated in the applicable prospectus supplement.

Our Options

We may issue options for the purchase of common units, preferred securities, subordinated securities or any combination of the foregoing. Our partnership agreement authorizes us to issue an unlimited number of options to purchase common units, preferred securities or subordinated securities for the consideration and with the rights, preferences, and privileges established by our general partner without the approval of any of our limited partners. Options may be issued independently or together with other securities and may be attached to or separate from any offered securities. Each series of options will be issued under a separate option agreement to be entered into between us and a bank or trust company, as option agent. The option agent will act solely as our agent in connection with the options and will not have any obligation or relationship of agency or trust for or with any holders or beneficial owners of options. A copy of the option agreement will be filed with the Commission in connection with the offering of options.

The prospectus supplement relating to a particular issue of options to purchase common units, preferred securities, subordinated securities or any combination of the foregoing will describe the terms of such options, including, among other things, the following:

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the title of the options;

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the offering price for the options, if any;

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the aggregate number of the options;

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the designation and terms of the common units, preferred securities, or subordinated securities that maybe purchased upon exercise of the options;

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if applicable, the designation and terms of the securities that the options are issued with and the number of options issued with each security;

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if applicable, the date from and after which the options and any securities issued with the options will be separately transferable;

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the number of common units, preferred securities, or subordinated securities that may be purchased upon exercise of the options and the price at which such securities may be purchased upon exercise;

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the dates on which the right to exercise the options commence and expire;

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if applicable, the minimum or maximum amount of the options that may be exercised at any one time;

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the currency or currency units in which the offering price, if any, and the exercise price are payable;

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if applicable, a discussion of material federal income tax considerations;

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anti-dilution provisions of the options, if any;

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redemption or call provisions, if any, applicable to the options;

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any additional terms of the options, including terms, procedures, and limitations relating to the exchange and exercise of the options; and

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any other information we think is important about the options.

Each option will entitle the holder of the option to purchase at the exercise price set forth in the applicable prospectus supplement the number of common units, preferred securities, or subordinated securities being offered. Holders may exercise options at any time up to the close of business on the expiration date set forth in the applicable prospectus supplement. After the close of business on the expiration date, unexercised options are void. Holders may exercise options as set forth in the prospectus supplement relating to the options being offered.

Until you exercise your options to purchase our common units, preferred securities or subordinated securities, you will not have any rights as a holder of common units, preferred securities or subordinated securities, as the case may be, by virtue of your ownership of options.

Our Warrants

We may issue warrants for the purchase of common units, preferred securities, subordinated securities or any combination of the foregoing. Our partnership agreement authorizes us to issue an unlimited number of warrants to purchase common units, preferred securities or subordinated securities for the consideration and with the rights, preferences, and privileges established by our general partner without the approval of any of our limited partners. Warrants may be issued independently or together with other securities and may be attached to or separate from any offered securities. Each series of warrants will be issued under a separate warrant agreement to be entered into between us and a bank or trust company, as warrant agent. The warrant agent will act solely as our agent in connection with the warrants and will not have any obligation or relationship of agency or trust for or with any holders or beneficial owners of warrants. A copy of the warrant agreement will be filed with the Commission in connection with the offering of warrants.

The prospectus supplement relating to a particular issue of warrants to purchase common units, preferred securities, subordinated securities or any combination of the foregoing will describe the terms of such warrants, including, among other things, the following:

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the title of the warrants;

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the offering price for the warrants, if any;

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the aggregate number of the warrants;

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the designation and terms of the common units, preferred securities or subordinated securities that maybe purchased upon exercise of the warrants;

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if applicable, the designation and terms of the securities that the warrants are issued with and the number of warrants issued with each security;

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if applicable, the date from and after which the warrants and any securities issued with the warrants will be separately transferable;

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the number of common units, preferred securities or subordinated securities that may be purchased upon exercise of a warrant and the price at which such securities may be purchased upon exercise;

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the dates on which the right to exercise the warrants commence and expire;

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if applicable, the minimum or maximum amount of the warrants that may be exercised at any one time;

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the currency or currency units in which the offering price, if any, and the exercise price are payable;

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if applicable, a discussion of material federal income tax considerations;

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anti-dilution provisions of the warrants, if any;

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redemption or call provisions, if any, applicable to the warrants;

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any additional terms of the warrants, including terms, procedures, and limitations relating to the exchange and exercise of the warrants; and

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any other information we think is important about the warrants.

Each warrant will entitle the holder of the warrant to purchase the number of common units, preferred securities or subordinated securities being offered at the exercise price set forth in the applicable prospectus supplement. Holders may exercise warrants at any time up to the close of business on the expiration date set forth in the applicable prospectus supplement. After the close of business on the expiration date, unexercised warrants are void. Holders may exercise warrants as set forth in the prospectus supplement relating to the warrants being offered.

Until you exercise your warrants to purchase our common units, preferred securities or subordinated securities, you will not have any rights as a holder of common units, preferred securities or subordinated securities, as the case may be, by virtue of your ownership of warrants.

Our Rights

We may issue rights to purchase common units, preferred securities, subordinated securities or any combination of the foregoing. Our partnership agreement authorizes us to issue an unlimited number of rights to purchase common units, preferred securities or subordinated securities for the consideration and with the rights, preferences, and privileges established by our general partner without the approval of any of our limited partners. These rights may be issued independently or together with any other security offered hereby and may or may not be transferable by the holder receiving the rights in such offering. In connection with any offering of such rights, we may enter into a standby arrangement with one or more underwriters or other purchasers pursuant to which the underwriters or other purchasers may be required to purchase any securities remaining unsubscribed for after such offering.

Each series of rights will be issued under a separate rights agreement, which we will enter into with a bank or trust company, as rights agent, all as set forth in the applicable prospectus supplement. The rights agent will act solely as our agent in connection with the certificates relating to the rights and will not assume any obligation or relationship of agency or trust with any holders of rights certificates or beneficial owners of rights. We will file the rights agreement and the rights certificates relating to each series of rights with the Commission, and incorporate them by reference as an exhibit to the registration statement of which this prospectus is a part on or before the time we issue a series of rights.

The applicable prospectus supplement will describe the specific terms of any offering of rights for which this prospectus is being delivered, including, among other things, the following:

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the date of determining the unitholders entitled to the rights distribution;

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the number of rights issued or to be issued to each unitholder;

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the exercise price payable for each common unit, preferred security or subordinated security upon the exercise of the rights;

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the number and terms of the common units, preferred securities or subordinated securities, which may be purchased per each right;

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the extent to which the rights are transferable;

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the date on which the holder’s ability to exercise the rights shall commence, and the date on which the rights shall expire;

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the extent to which the rights may include an over-subscription privilege with respect to unsubscribed securities;

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if applicable, the material terms of any standby underwriting or purchase arrangement entered into by us in connection with the offering of such rights;

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any other terms of the rights, including the terms, procedures, conditions, and limitations relating to the exchange and exercise of the rights; and

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any other information we think is important about the rights.

The description in the applicable prospectus supplement of any rights that we may offer will not necessarily be complete and will be qualified in its entirety by reference to the applicable rights agreement and rights certificate, which will be filed with the Commission.

CASH DISTRIBUTION POLICY

Distributions of Available Cash

General. Within approximately 45 days after the end of each quarter, Genesis Energy, L.P. will distribute all available cash to unitholders of record on the applicable record date. However, there is no guarantee that we will pay a distribution on our units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or if an event of default then exists, under our credit facility.

Definition of Available Cash. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

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less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or appropriate to:

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provide for the proper conduct of our business;

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

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provide funds for distributions to our unitholders for any one or more of the next four quarters;

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plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings. Working capital borrowings are generally borrowings that are made under our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Adjustment of Quarterly Distribution Amounts

If we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust the amount of our quarterly distribution.

For example, if a two-for-one split of the common units should occur, the quarterly distribution and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders, 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.

DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. Our partnership agreement has been filed with the Commission, and is incorporated by reference in this prospectus. The following provisions of our partnership agreement are summarized elsewhere in this prospectus:

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allocations of taxable income and other tax matters are described under “Material Income Tax Consequences”; and

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rights of holders of common units are described under “Description of Our Equity Securities — Our Common Units.”

Partnership Purpose

Our purpose under our partnership agreement is to engage directly or indirectly in any business activity that is approved by our general partner and that may be lawfully conducted by a limited partnership under the Delaware Act. All of our operations are conducted through our subsidiaries and joint ventures.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Reimbursements of Our General Partner

Our general partner does not receive any compensation for its services as our general partner. It is, however, entitled to be reimbursed for all of its costs incurred in managing and operating our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partner securities and rights to buy partnership securities that are equal in rank with or junior to our common units on terms and conditions established by our general partner in its sole discretion without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional equity securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional equity securities that, in the sole discretion of our general partner, may have special voting rights to which common units are not entitled.

Amendments to Our Partnership Agreement

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. Any amendment that materially and adversely affects the rights or preferences of any type or class of

limited partner interests in relation to other types or classes of limited partner interests or our general partner interest will require the approval of at least a majority of the type or class of limited partner interests or general partner interests so affected.

However, in some circumstances, more particularly described in our partnership agreement, our general partner may make amendments to our partnership agreement without the approval of our limited partners or assignees.

Withdrawal or Removal of Our General Partner

Our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement.

Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding common units may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal, the holders of a majority of our outstanding common units agree in writing to continue our business and to appoint a successor general partner.

Our general partner may be removed with or without cause. “Cause” means that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. If cause exists, our general partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of our outstanding units, including units held by our general partner and its affiliates. The removal of our general partner for cause is also subject to the approval of a successor general partner by a vote of the holders of not less than two-thirds of our outstanding units, including units held by our general partner and its affiliates. If no cause exists, our general partner may not be removed unless that removal is approved by the vote of the holders of not less than a majority of our outstanding units, excluding units held by our general partner and its affiliates. Any removal of our general partner by the unitholders without cause is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units and the receipt of an opinion of counsel regarding limited liability and tax matters. Additionally, upon removal of our general partner without cause, our general partner will have the option to convert its interest in us (other than its common units) into common units or to require our replacement general partner to purchase such interest for cash at its then fair market value.

While our partnership agreement limits the ability of our general partner to withdraw, it allows our general partner interest to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of our general partner. In addition, our partnership agreement does not prohibit the sale, in whole or in part, of the ownership of our general partner. Our general partner may also transfer, in whole or in part, the common units and any other partnership securities it owns.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:

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first, towards the payment of all of our creditors; and

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then, to our unitholders in accordance with the positive balance in their respective capital accounts.

The liquidator may defer liquidation of our assets for a reasonable period or distribute assets to our partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Change of Management Provisions

Our partnership agreement contains the following specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change management:

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any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matters pertaining to the succession, election, removal, withdrawal, replacement or substitution of our general partner; and

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the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Limited Call Right

If at any time our general partner, Genesis and their respective subsidiaries own more than 80% of the issued and outstanding limited partner interests of any class, our general partner will have the right to acquire all, but not less than all, of the outstanding limited partner interests of that class that are held by persons other than our general partner, Genesis and their respective subsidiaries. The record date for determining ownership of the limited partner interests would be selected by our general partner on at least ten but not more than 60 days notice. The purchase price in the event of a purchase under these provisions would be the greater of (1) the current market price (as defined in our partnership agreement) of the limited partner interests of the class as of the date three days prior to the date that notice is mailed to the limited partners as provided in the partnership agreement and (2) the highest cash price paid by our general partner, Genesis or any of their respective subsidiaries for any partnership securities of the class purchased within the 90 days preceding the date our general partner first mails notice of its election to purchase those partnership securities.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify persons who are or were our general partner, or its members or other affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer because they are or were our general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to our best interest. Any indemnification under these provisions will only be out of our assets. Our general partner and its affiliates shall not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate any indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement. In addition, we typically enter into indemnification agreements with each director of our general partner covering any costs, claims or expenses such director incurs in connection with serving in her/his capacity as a director or any other capacity at the request of our general partner or us.

DESCRIPTION OF DEBT SECURITIES AND GUARANTEES

General

Genesis Energy, L.P. may issue debt securities in one or more series, as to any of which Genesis Energy Finance Corporation (“Finance Corp.”) may be a co-issuer on one or more series of such debt securities. Finance Corp. was incorporated under the laws of the State of Delaware in November 2006, is wholly owned by Genesis Energy, L.P., and has no material assets or any liabilities other than as a co-issuer of debt securities. When used in this section, references to “we,” “us” and “our” refer to Genesis Energy, L.P. and, if Finance Corp. is co-issuer as to any series of debt securities, Genesis Energy Finance Corporation.

We may issue senior or subordinated debt securities. Neither the senior debt securities nor the subordinated debt securities will be secured by any of our property or assets. Thus, by owning a debt security, you are one of our unsecured creditors.

The senior debt securities will constitute part of our senior debt, will be issued under our senior debt indenture described below and will rank equally with all of our other unsecured and unsubordinated debt.

The subordinated debt securities will constitute part of our subordinated debt, will be issued under our subordinated debt indenture described below and will be subordinate in right of payment to all of our “senior debt,” as defined in the indenture with respect to subordinated debt securities. The prospectus supplement for any series of subordinated debt securities or the information incorporated in this prospectus by reference will indicate the approximate amount of senior debt outstanding as of the end of our most recent fiscal quarter. Neither indenture limits our ability to incur additional senior debt or other indebtedness.

When we refer to “debt securities” in this prospectus, we mean both the senior debt securities and the subordinated debt securities.

The debt securities may have the benefit of guarantees (each, a “guarantee”) by one or more existing or future subsidiaries of Genesis Energy, L.P. (each, a “guarantor”) specified in the prospectus supplement for that series. If a guarantor issues guarantees, the guarantees will be the unsecured and, if guaranteeing senior debt securities, unsubordinated or, if guaranteeing subordinated debt securities, subordinated obligations of the respective guarantors. Unless otherwise expressly stated or the context otherwise requires, as used in this section, the term “guaranteed debt securities” means debt securities that, as described in the prospectus supplement relating thereto, are guaranteed by one or more guarantors pursuant to the applicable indenture.

The debt indentures and their associated documents, including your debt security, contain the full legal text of the matters described in this section and your prospectus supplement. We have filed forms of the indentures with the Commission as exhibits to our registration statement, of which this prospectus is a part. See “Where You Can Find More Information” below for information on how to obtain copies of them.

This section and your prospectus supplement summarize material terms of the indentures and your debt security. They do not, however, describe every aspect of the indentures and your debt security. For example, in this section and your prospectus supplement, we use terms that have been given special meaning in the indentures, but we describe the meaning for only the more important of those terms. Your prospectus supplement will have a more detailed description of the specific terms of your debt security and any applicable guarantees.

Indentures

The senior debt securities and subordinated debt securities are each governed by a document each called an indenture. Each indenture is a contract between us and U.S. Bank National Association. The indentures are substantially identical, except for certain provisions including those relating to subordination, which are included only in the indenture related to subordinated debt securities.

The trustee under each indenture has two main roles:

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First, the trustee can enforce your rights against us if we default. There are some limitations on the extent to which the trustee acts on your behalf, which we describe later under “— Default, Remedies and Waiver of Default.”

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Second, the trustee performs administrative duties for us, such as sending you interest payments and notices.

When we refer to the indenture or the trustee with respect to any debt securities, we mean the indenture under which those debt securities are issued and the trustee under that indenture.

Series of Debt Securities

We may issue as many distinct debt securities or series of debt securities under either indenture as we wish. This section summarizes terms of the securities that apply generally to all debt securities and series of debt securities. The provisions of each indenture allow us not only to issue debt securities with terms different from those of debt securities previously issued under that indenture, but also to “reopen” a previously issued series of debt securities and issue additional debt securities of that series. We will describe most of the financial and other specific terms of your series, whether it be a series of the senior debt securities or subordinated debt securities, in the prospectus supplement for that series. Those terms may vary from the terms described herein.

As you read this section, please remember that the specific terms of your debt security as described in your prospectus supplement will supplement and, if applicable, may modify or replace the general terms described in this section. If there are any differences between your prospectus supplement and this prospectus, your prospectus supplement will control. Thus, the statements we make in this section may not apply to your debt security.

When we refer to “debt securities” or a “series of debt securities,” we mean, respectively, debt securities or a series of debt securities issued under the applicable indenture. When we refer to your prospectus supplement, we mean the prospectus supplement describing the specific terms of the debt security you purchase. The terms used in your prospectus supplement will have the meanings described in this prospectus, unless otherwise specified.

Amounts of Issuances

Neither indenture limits the aggregate amount of debt securities that we may issue or the number of series or the aggregate amount of any particular series. We may issue debt securities and other securities at any time without your consent and without notifying you.

The indentures and the debt securities do not limit our ability to incur other indebtedness or to issue other securities. Also, unless otherwise specified below or in your prospectus supplement, we are not subject to financial or similar restrictions by the terms of the debt securities.

Principal Amount, Stated Maturity and Maturity

Unless otherwise stated, the principal amount of a debt security means the principal amount payable at its stated maturity, unless that amount is not determinable, in which case the principal amount of a debt security is its face amount.

The term “stated maturity” with respect to any debt security means the fixed date stated in such debt security on which the principal amount of such debt security is scheduled to become due. The principal may become due sooner, by reason of redemption or acceleration after a default or otherwise in accordance with the terms of the debt security. The day on which the principal actually becomes due, whether at the stated maturity or earlier, is called the “maturity” of the principal.

We also use the terms “stated maturity” and “maturity” to refer to the days when other payments become due. For example, we may refer to a regular interest payment date when an installment of interest is scheduled to become due as the “stated maturity” of that installment. When we refer to the “stated maturity” or the “maturity” of a debt security without specifying a particular payment, we mean the stated maturity or maturity, as the case may be, of the principal.

Specific Terms of Debt Securities

Your prospectus supplement will describe the specific terms of your debt security, which will include some or all of the following:

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whether Finance Corp. will be a co-issuer of your debt security;

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the title of the series of your debt security and whether it is a senior debt security or a subordinated debt security;

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any limit on the total principal amount of the debt securities of the same series;

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the stated maturity;

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the currency or currencies for principal and interest, if not United States, or U.S., dollars;

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the price at which we originally issue your debt security, expressed as a percentage of the principal amount, and the original issue date;

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whether your debt security is a fixed rate debt security, a floating rate debt security or an indexed debt security;

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if your debt security is a fixed rate debt security, the yearly rate at which your debt security will bear interest, if any, and the interest payment dates;

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if your debt security is a floating rate debt security, the interest rate basis; any applicable index currency or index maturity, spread or spread multiplier or initial base rate, maximum rate or minimum rate; the interest reset, determination, calculation and payment dates; the day count convention used to calculate interest payments for any period; the business day convention; and the calculation agent;

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if your debt security is an indexed debt security, the principal amount, if any, we will pay you at maturity, interest payment dates, the amount of interest, if any, we will pay you on an interest payment date or the formula we will use to calculate these amounts, if any, and the terms on which your debt security will be exchangeable for or payable in cash, securities or other property;

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if your debt security may be converted into or exercised or exchanged for common units, preferred securities or other securities of Genesis Energy, L.P. or debt or equity securities of one or more third parties, the terms on which conversion, exercise or exchange may occur, including whether conversion, exercise or exchange is mandatory, at the option of the holder or at our option, the period during which conversion, exercise or exchange may occur, the initial conversion, exercise or exchange price or rate and the circumstances or manner in which the amount of common or preferred securities or other securities issuable upon conversion, exercise or exchange may be adjusted;

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if your debt security is also an original issue discount debt security, the yield to maturity;

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if applicable, the circumstances under which your debt security may be redeemed at our option or repaid at the holder’s option before the stated maturity, including any redemption commencement date, repayment date(s), redemption price(s) and redemption period(s);

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the authorized denominations, if other than $2,000 and integral multiples of $1,000;

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the depositary for your debt security, if other than The Depository Trust Company (“DTC”), and any circumstances under which the holder may request securities in non-global form, if we choose not to issue your debt security in book-entry form only;

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if applicable, the circumstances under which we will pay additional amounts on any debt securities held by a person who is not a U.S. person for tax purposes and under which we can redeem the debt securities if we have to pay additional amounts;

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whether your debt security will be guaranteed by any guarantors and, if so, the identity of the guarantors and, to the extent the terms thereof differ from those described in this prospectus, a description of the terms of the guarantees;

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the names and duties of any co-trustees, depositaries, authenticating agents, paying agents, transfer agents or registrars for your debt security, as applicable; and

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any other terms of your debt security and any guarantees of your debt security, which could be different from those described in this prospectus.

Governing Law

The indentures and the debt securities (and any guarantees thereof) will be governed by New York law.

Form of Debt Securities

We will issue each debt security only in registered form, without coupons, unless we specify otherwise in the applicable prospectus supplement. In addition, we will issue each debt security in global — i.e., book-entry — form only, unless we specify otherwise in the applicable prospectus supplement. Debt securities in book-entry form will be represented by a global security registered in the name of a depositary, which will be the holder of all the debt securities represented by the global security. Those who own beneficial interests in a global debt security will do so through participants in the depositary’s securities clearance system, and the rights of these indirect owners will be governed solely by the applicable procedures of the depositary and its participants. References to “holders” in this section mean those who own debt securities registered in their own names, on the books that we or the trustee maintain for this purpose, and not those who own beneficial interests in debt securities registered in street name or in debt securities issued in book-entry form through one or more depositaries.

Unless otherwise indicated in the prospectus supplement, the following is a summary of the depositary arrangements applicable to debt securities issued in global form and for which DTC acts as depositary.

Each global debt security will be deposited with, or on behalf of, DTC, as depositary, or its nominee, and registered in the name of a nominee of DTC. Except under the limited circumstances described below, global debt securities are not exchangeable for definitive certificated debt securities.

Ownership of beneficial interests in a global debt security is limited to institutions that have accounts with DTC or its nominee, or persons that may hold interests through those participants. In addition, ownership of beneficial interests by participants in a global debt security will be evidenced only by, and the transfer of that ownership interest will be effected only through, records maintained by DTC or its nominee for a global debt security. Ownership of beneficial interests in a global debt security by persons that hold those interests through participants will be evidenced only by, and the transfer of that ownership interest within that participant will be effected only through, records maintained by that participant. DTC has no knowledge of the actual beneficial owners of the debt securities. Beneficial owners will not receive written confirmation from DTC of their purchase, but beneficial owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the participants through which the beneficial owners entered the transaction. The laws of some jurisdictions require that certain purchasers of securities take physical delivery of securities they purchase in definitive form. These laws may impair your ability to transfer beneficial interests in a global debt security.

We will make payment of principal of, and interest on, debt securities represented by a global debt security registered in the name of or held by DTC or its nominee to DTC or its nominee, as the case may be, as the registered owner and holder of the global debt security representing those debt securities. DTC has advised us that upon receipt of any payment of principal of, or interest on, a global debt security, DTC immediately will credit accounts of participants on its book-entry registration and transfer system with payments in amounts proportionate to their respective interests in the principal amount of that global debt security, as shown in the records of DTC. Payments by participants to owners of beneficial interests in a global debt security held through those participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers in bearer form or registered in “street name,” and will be the sole responsibility of those participants, subject to any statutory or regulatory requirements that may be in effect from time to time.

Neither we, any trustee nor any of our respective agents will be responsible for any aspect of the records of DTC, any nominee or any participant relating to, or payments made on account of, beneficial interests in a permanent global debt security or for maintaining, supervising or reviewing any of the records of DTC, any nominee or any participant relating to such beneficial interests.

A global debt security is exchangeable for definitive debt securities registered in the name of, and a transfer of a global debt security may be registered to, any person other than DTC or its nominee, only if:

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DTC notifies us that it is unwilling or unable to continue as depositary for that global security or has ceased to be a registered clearing agency and we do not appoint another institution to act as depositary within 90 days; or

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we notify the trustee that we wish to terminate that global security.

Any global debt security that is exchangeable pursuant to the preceding sentence will be exchangeable in whole for definitive debt securities in registered form, of like tenor and of an equal aggregate principal amount as the global debt security, in denominations specified in the applicable prospectus supplement, if other than $2,000 and multiples of $1,000. The definitive debt securities will be registered by the registrar in the name or names instructed by DTC. We expect that these instructions may be based upon directions received by DTC from its participants with respect to ownership of beneficial interests in the global debt security.

Except as provided above, owners of the beneficial interests in a global debt security will not be entitled to receive physical delivery of debt securities in definitive form and will not be considered the holders of debt securities for any purpose under the indentures. No global debt security shall be exchangeable except for another global debt security of like denomination and tenor to be registered in the name of DTC or its nominee. Accordingly, each person owning a beneficial interest in a global debt security must rely on the procedures of DTC and, if that person is not a participant, on the procedures of the participant through which that person owns its interest, to exercise any rights of a holder under the global debt security or the indentures.

We understand that, under existing industry practices, in the event that we request any action of holders, or an owner of a beneficial interest in a global debt security desires to give or take any action that a holder is entitled to give or take under the debt securities or the indentures, DTC would authorize the participants holding the relevant beneficial interests to give or take that action. Additionally, those participants would authorize beneficial owners owning through those participants to give or take that action or would otherwise act upon the instructions of beneficial owners owning through them.

DTC has advised us that it is a limited-purpose trust company organized under the laws of the State of New York, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). DTC was created to hold securities of its participants and to facilitate the clearance and settlement of transactions

among its participants in securities through electronic book-entry changes in accounts of the participants. By doing so, DTC eliminates the need for physical movement of securities certificates. DTC’s participants include securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is owned by a number of its participants and by the New York Stock Exchange, Inc., NYSE Amex Equities. Access to DTC’s book-entry system is also available to others, such as banks, brokers, dealers, and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly. The rules applicable to DTC and its participants are on file with the Commission.

Investors may hold interests in the debt securities outside the U.S. through the Euroclear System (“Euroclear”) or Clearstream Banking (“Clearstream”) if they are participants in those systems, or indirectly through organizations which are participants in those systems. Euroclear and Clearstream will hold interests on behalf of their participants through customers’ securities accounts in Euroclear’s and Clearstream’s names on the books of their respective depositaries, which in turn will hold such interests in customers’ securities accounts in the depositaries’ names on the books of DTC.

Euroclear advises that it was created in 1968 to hold securities for participants of Euroclear (“Euroclear Participants”) and to clear and settle transactions between Euroclear Participants through simultaneous electronic book-entry delivery against payment, thereby eliminating the need for physical movement of certificates and any risk from lack of simultaneous transfers of securities and cash. Euroclear includes various other services, including securities lending and borrowing and interfaces with domestic markets in several countries. Euroclear is operated by the Euroclear S.A./N.V. (the “Euroclear Operator”), under contract with Euroclear Clearance Systems S.C., a Belgian cooperative corporation (the “Cooperative”). All operations are conducted by the Euroclear Operator, and all Euroclear securities clearance accounts and Euroclear cash accounts are accounts with the Euroclear Operator, not the Cooperative. The Cooperative establishes policy for Euroclear on behalf of Euroclear Participants. Euroclear Participants include banks (including central banks), securities brokers and dealers, and other professional financial intermediaries and may include any agents. Indirect access to Euroclear is also available to other firms that clear through or maintain a custodial relationship with a Euroclear Participant, either directly or indirectly.

Securities clearance accounts and cash accounts with the Euroclear Operator are governed by the Terms and Conditions Governing Use of Euroclear, the related Operating Procedures of the Euroclear System, and applicable Belgian law (collectively, the “Terms and Conditions”). The Terms and Conditions govern transfers of securities and cash within Euroclear, withdrawals of securities and cash within Euroclear, withdrawals of securities and cash from Euroclear, and receipts of payments with respect to securities in Euroclear. All securities in Euroclear are held on a fungible basis without attribution of specific certificates to specific securities clearance accounts. The Euroclear Operator acts under the Terms and Conditions only on behalf of Euroclear Participants and has no record of or relationship with persons holding through Euroclear Participants.

Distributions with respect to debt securities held beneficially through Euroclear will be credited to the cash accounts of Euroclear Participants in accordance with the Terms and Conditions, to the extent received by the U.S. depositary for Euroclear.

Clearstream advises that it is incorporated under the laws of Luxembourg as a professional depositary. Clearstream holds securities for its participating organizations (“Clearstream Participants”) and facilitates the clearance and settlement of securities transactions between Clearstream Participants through electronic book-entry changes in accounts of Clearstream Participants, thereby eliminating the need for physical movement of certificates. Clearstream provides to Clearstream Participants, among other things, services for safekeeping, administration, clearance, and settlement of internationally traded securities and securities lending and borrowing. Clearstream interfaces with domestic markets in several countries. As a professional depositary, Clearstream is subject to regulation by the Luxembourg Monetary Institute. Clearstream Participants are recognized financial institutions around the world, including agents, securities brokers and dealers, banks, trust

companies, clearing corporations, and certain other organizations and may include any agents. Indirect access to Clearstream is also available to others, such as banks, brokers, dealers, and trust companies that clear through or maintain a custodial relationship with a Clearstream Participant either directly or indirectly.

Distributions with respect to debt securities held beneficially through Clearstream will be credited to cash accounts of Clearstream Participants in accordance with its rules and procedures, to the extent received by the U.S. depositary for Clearstream.

We have provided the descriptions herein of the operations and procedures of DTC, Euroclear and Clearstream solely as a matter of convenience. These operations and procedures are solely within the control of DTC, Euroclear and Clearstream and are subject to change by them from time to time. We believe that the sources from which the information in this section and elsewhere in this prospectus concerning DTC, Euroclear, the Euroclear Operator, the Cooperative, Euroclear’s system, Clearstream and Clearstream’s system has been obtained are reliable, but neither we, any underwriters nor the trustee takes any responsibility for the accuracy of the information.

Initial settlement for the securities will be made in immediately available funds. Secondary market trading between DTC participants will occur in the ordinary way in accordance with DTC’s rules and will be settled in immediately available funds. Secondary market trading between Euroclear Participants and/or Clearstream Participants will occur in the ordinary way in accordance with the applicable rules and operating procedures of Euroclear and Clearstream, as applicable, and will be settled using the procedures applicable to conventional eurobonds in immediately available funds.

Cross-market transfers between persons holding directly or indirectly through DTC, on the one hand, and directly or indirectly through Euroclear Participants or Clearstream Participants, on the other, will be effected in DTC in accordance with DTC rules on behalf of the relevant European international clearing system by its U.S. depositary; however, such cross-market transactions will require delivery of instructions to the relevant European international clearing system by the counterparty in such system in accordance with its rules and procedures and within its established deadlines (European time). The relevant European international clearing system will, if the transaction meets its settlement requirements, deliver instructions to its U.S. depositary to take action to effect final settlement on its behalf by delivering or receiving securities in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear Participants and Clearstream Participants may not deliver instructions directly to their respective U.S. depositaries.

Because of time-zone differences, credits of securities received in Euroclear or Clearstream as a result of a transaction with a DTC participant will be made during subsequent securities settlement processing and dated the business day following the DTC settlement date. Credits or any transactions in securities settled during this processing will be reported to the relevant Euroclear or Clearstream Participants on that following business day. Cash received in Euroclear or Clearstream as a result of sales of debt securities by or through a Euroclear Participant or a Clearstream Participant to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Euroclear or Clearstream cash account only as of the business day following settlement in DTC.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of securities among participants of DTC, Euroclear and Clearstream, they are under no obligation to perform or continue to perform these procedures and these procedures may be discontinued at any time.

Redemption or Repayment

If there are any provisions regarding redemption or repayment applicable to your debt security, we will describe them in your prospectus supplement.

We or our affiliates may purchase debt securities from investors who are willing to sell from time to time, either in the open market at prevailing prices or in private transactions at negotiated prices. Debt securities that we or they purchase may, at our discretion, be held, resold or canceled.

Mergers and Similar Transactions

Each of Genesis Energy, L.P. and Finance Corp. (each, an “issuer”) is generally permitted under the indenture for the relevant series to merge or consolidate with another corporation or other entity. Each issuer is also permitted under the indenture for the relevant series to sell all or substantially all of its assets to another corporation or other entity. With regard to any series of debt securities, however, no issuer may take any of these actions unless all the following conditions, among other things, are met:

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If the successor entity in the transaction is not such issuer, (a) the successor entity must be organized as a corporation, limited liability company, partnership or trust, and must expressly assume such issuer’s obligations under the debt securities of that series and the indenture with respect to that series and (b) if Finance Corp. initially was a co-issuer as to that series, immediately after such transaction, an issuer as to that series must be a corporation. The successor entity may be organized under the laws of the U.S., any state thereof or the District of Columbia.

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Immediately after the transaction, no default under the debt securities of that series has occurred and is continuing. For this purpose, “default under the debt securities of that series” means an event of default with respect to that series or any event that would be an event of default with respect to that series if the requirements for giving us default notice and for our default having to continue for a specific period of time were disregarded. We describe these matters below under “— Default, Remedies and Waiver of Default.”

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Such issuer has delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger, sale, conveyance, transfer or lease and, if a supplemental indenture is required in connection with such transaction, such supplemental indenture comply with this covenant and that all conditions precedent in the indenture provided for relating to such transaction have been complied with.

If the conditions described above are satisfied with respect to the debt securities of any series, an issuer will not need to obtain the approval of the holders of those debt securities in order to merge or consolidate or to sell its assets. Also, these conditions will apply only if an issuer wishes to merge or consolidate with another entity or sell all or substantially all of our assets to another entity. We will not need to satisfy these conditions if we enter into other types of transactions, including any transaction in which we acquire the stock or assets of another entity, any transaction that involves a change of control of us but in which we do not merge or consolidate and any transaction in which we sell less than substantially all our assets.

The successor entity will be substituted for an issuer of the debt securities of any series and under the indenture with the same effect as if it had been an original party to the indenture, and, except in the case of a lease, such issuer will be relieved from any further obligations and covenants under the indenture.

Subordination Provisions

Holders of subordinated debt securities should recognize that contractual provisions in the subordinated debt indenture may prohibit us from making payments on those securities. Subordinated debt securities are subordinate and junior in right of payment, to the extent and in the manner stated in the subordinated debt indenture, to all of our senior debt, as defined in the subordinated debt indenture, including all debt securities we have issued and will issue under the senior debt indenture.

The subordinated debt indenture defines “senior debt” as:

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our indebtedness under or in respect of our credit agreement, whether for principal, interest (including interest accruing after the filing of a petition initiating any proceeding pursuant to any bankruptcy law, whether or not the claim for such interest is allowed as a claim in such proceeding), reimbursement obligations, fees, commissions, expenses, indemnities or other amounts; and

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any other indebtedness permitted under the terms of that indenture, unless the instrument under which such indebtedness is incurred expressly provides that it is on a parity with or subordinated in right of payment to the subordinated debt securities.

Notwithstanding the foregoing, “senior debt” will not include: (i) equity interests; (ii) any liability for taxes; (iii) any indebtedness to any of our subsidiaries or affiliates; (iv) any trade payables; or (v) any indebtedness incurred in violation of the subordinated debt indenture.

We may modify the subordination provisions, including the definition of senior debt, with respect to one or more series of subordinated debt securities. Such modifications will be set forth in the applicable prospectus supplement.

The subordinated debt indenture provides that, unless all principal of and any premium or interest on the senior debt has been paid in full, no payment or other distribution may be made in respect of any subordinated debt securities in the following circumstances:

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in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization, assignment for creditors or other similar proceedings or events involving us or our assets;

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(a) in the event and during the continuation of any default in the payment of principal, premium or interest on any senior debt beyond any applicable grace period or (b) in the event that any event of default with respect to any senior debt has occurred and is continuing, permitting the holders of that senior debt (or a trustee) to accelerate the maturity of that senior debt, whether or not the maturity is in fact accelerated (unless, in the case of (a) or (b), the payment default or event of default has been cured or waived or ceased to exist and any related acceleration has been rescinded) or (c) in the event that any judicial proceeding is pending with respect to a payment default or event of default described in (a) or (b); or

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in the event that any subordinated debt securities have been declared due and payable before their stated maturity.

If the trustee under the subordinated debt indenture or any holders of the subordinated debt securities receive any payment or distribution that is prohibited under the subordination provisions, then the trustee or the holders will have to repay that money to the holders of the senior debt.

Even if the subordination provisions prevent us from making any payment when due on the subordinated debt securities of any series, we will be in default on our obligations under that series if we do not make the payment when due. This means that the trustee under the subordinated debt indenture and the holders of that series can take action against us, but they will not receive any money until the claims of the holders of senior debt have been fully satisfied.

The subordinated debt indenture allows the holders of senior debt to obtain a court order requiring us and any holder of subordinated debt securities to comply with the subordination provisions.

Defeasance, Covenant Defeasance and Satisfaction and Discharge

When we use the term defeasance, we mean discharge from some or all of our obligations under the indenture. If we deposit with the trustee funds or government securities, or if so provided in your prospectus supplement, obligations other than government securities, sufficient to make payments on any series of debt securities on the dates those payments are due and payable and other specified conditions are satisfied, then, at our option, either of the following will occur:

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we will be discharged from our obligations with respect to the debt securities of such series and all obligations of any guarantors of such debt securities will also be discharged with respect to the guarantees of such debt securities (“legal defeasance”); or

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we will be discharged from any covenants we make in the applicable indenture for the benefit of such series and the related events of default will no longer apply to us (“covenant defeasance”).

If we defease any series of debt securities, the holders of such securities will not be entitled to the benefits of the indenture, except for our obligations to deliver temporary and definitive securities, register the transfer or exchange of such securities, replace stolen, lost or mutilated securities or maintain paying agencies, hold moneys for payment in trust and make payments from such trust of principal, premium and interest on the applicable series of debt securities when due. In case of covenant defeasance, our obligation to pay principal, premium and interest on the applicable series of debt securities will also survive.

We will be required to deliver to the trustee an opinion of counsel that the deposit and related defeasance would not cause the holders of the applicable series of debt securities to recognize gain or loss for federal income tax purposes. If we elect legal defeasance, that opinion of counsel must be based upon a ruling from the U.S. Internal Revenue Service, or IRS, or a change in law to that effect.

Upon the effectiveness of defeasance with respect to any series of guaranteed debt securities, each guarantor of the debt securities of such series shall be automatically and unconditionally released and discharged from all of its obligations under its guarantee of the debt securities of such series and all of its other obligations under the applicable indenture in respect of the debt securities of that series, without any action by us, any guarantor or the trustee and without the consent of the holders of any debt securities.

In addition, we may satisfy and discharge all our obligations under the indenture with respect to debt securities of any series, other than our surviving obligations to convert, register the transfer of and exchange debt securities of that series, provided that either:

•

we deliver all outstanding debt securities of that series to the trustee for cancellation; or

•

all such debt securities not so delivered for cancellation have become due and payable, will become due and payable at their stated maturity within one year or are to be called for redemption within one year, and in the case of this bullet point, we have deposited with the trustee in trust an amount of cash sufficient to pay the entire indebtedness of such debt securities, including interest to the date of deposit (in the case of debt securities which have become due and payable), stated maturity or applicable redemption date.

No Personal Liability

No past, present or future director, officer, employee, incorporator, member, manager, partner (whether general or limited), unitholder or stockholder of us, the general partner of Genesis Energy, L.P. or any guarantor, as such, will have any liability for any obligations of us or any guarantor, respectively, under the debt securities or the indentures or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of debt securities by accepting a debt security waives and releases all such liability. The waiver and release are part of the consideration for issuance of the debt securities and any guarantees. The waiver may not be effective to waive liabilities under the federal securities laws.

Default, Remedies and Waiver of Default

You will have special rights if an event of default with respect to your series of debt securities occurs and is continuing, as described in this subsection.

Unless your prospectus supplement says otherwise, when we refer to an event of default with respect to any series of debt securities, we mean any of the following:

•

we do not pay the principal or any premium on any debt security of that series on the due date;

•

we do not pay interest on any debt security of that series within 30 days after the due date;

•

we do not deposit a sinking fund payment with regard to any debt security of that series within 60 days after the due date, but only if the payment is required under provisions described in the applicable prospectus supplement;

•

we remain in breach of our covenants regarding mergers or sales of substantially all of our assets or any other covenant we make in the indenture for the benefit of the relevant series, for 90 days after we receive a notice of default stating that we are in breach and requiring us to remedy the breach. The notice must be sent by the trustee or the holders of at least 25% in principal amount of the relevant series of debt securities;

•

we file for bankruptcy or other events of bankruptcy, insolvency or reorganization relating to us occur;

•

if the debt securities of that series are guaranteed debt securities, the guarantee of the debt securities of that series by any guarantor shall for any reason cease to be, or shall for any reason be asserted in writing by such guarantor or us, not to be, in full force and effect and enforceable in accordance with its terms, except to the extent contemplated or permitted by the indenture or the debt securities of that series; or

•

if the applicable prospectus supplement states that any additional event of default applies to the series, that event of default occurs.

We may change, eliminate, or add to the events of default with respect to any particular series or any particular debt security or debt securities within a series, as indicated in the applicable prospectus supplement.

Remedies if an Event of Default Occurs. If you are the holder of a subordinated debt security, all the remedies available upon the occurrence of an event of default under the subordinated debt indenture will be subject to the restrictions on the subordinated debt securities described above under “— Subordination Provisions.”

Except as otherwise specified in the applicable prospectus supplement, if an event of default has occurred with respect to any series of debt securities and has not been cured or waived, the trustee or the holders of not less than 25% in principal amount of all debt securities of that series then outstanding may declare the entire principal amount of the debt securities of that series to be due immediately. Except as otherwise specified in the applicable prospectus supplement, if the event of default occurs because of events in bankruptcy, insolvency or reorganization relating to us, the entire principal amount of the debt securities of that series will be automatically accelerated, without any action by the trustee or any holder.

Each of the situations described above is called an acceleration of the stated maturity of the affected series of debt securities. Except as otherwise specified in the applicable prospectus supplement, if the stated maturity of any series is accelerated and a judgment for payment has not yet been obtained, the holders of a majority in principal amount of the debt securities of that series may cancel the acceleration for the entire series, upon satisfaction of certain conditions.

If an event of default occurs, the trustee will have special duties. In that situation, the trustee will be obligated to use those of its rights and powers under the relevant indenture, and to use the same degree of care and skill in doing so, that a prudent person would use in that situation in conducting his or her own affairs.

Except as described in the prior paragraph, the trustee is not required to take any action under the relevant indenture at the request of any holders unless the holders offer the trustee reasonable protection from expenses and liability. This is called an indemnity. If the trustee is provided with an indemnity reasonably satisfactory to it, the holders of a majority in principal amount of all debt securities of the relevant series may direct the time, method and place of conducting any lawsuit or other formal legal action seeking any remedy available to the trustee with respect to that series. These majority holders may also direct the trustee in performing any other action under the relevant indenture with respect to the debt securities of that series.

Before you bypass the trustee and bring your own lawsuit or other formal legal action or take other steps to enforce your rights or protect your interests relating to any debt security, all of the following must occur:

•

the holder of your debt security must give the trustee written notice that an event of default has occurred with respect to the debt securities of your series, and the event of default must not have been cured or waived;

•

the holders of not less than 25% in principal amount of all debt securities of your series must make a written request that the trustee take action because of the default, and they or other holders must offer to the trustee indemnity reasonably satisfactory to the trustee against the cost and other liabilities of taking that action;

•

the trustee must not have taken action for 60 days after the above steps have been taken; and

•

during those 60 days, the holders of a majority in principal amount of the debt securities of your series must not have given the trustee directions that are inconsistent with the written request of the holders of not less than 25% in principal amount of the debt securities of your series.

You are entitled at any time, however, to bring a lawsuit for the payment of money due on your debt security on or after its stated maturity (or, if your debt security is redeemable, on or after its redemption date).

Book-entry and other indirect owners should consult their banks or brokers for information on how to give notice or direction to or make a request of the trustee and how to declare or cancel an acceleration of the maturity.

Waiver of Default. The holders of not less than a majority in principal amount of the debt securities of any series may waive a default for all debt securities of that series. If this happens, the default will be treated as if it has not occurred. No one can waive a payment default on your debt security, however, without the approval of the particular holder of that debt security.

Annual Information about Defaults to the Trustee. We will furnish each trustee every year a written statement of two of our officers certifying that to their knowledge we are in compliance with the applicable indenture and the debt securities issued under it, or else specifying any default under the applicable indenture.

Modifications and Waivers

There are four types of changes we can make to either indenture and the debt securities or series of debt securities or any guarantees thereof issued under that indenture.

Changes Requiring Each Holder’s Approval. First, there are changes that cannot be made without the approval of each holder of a debt security affected by the change under the applicable debt indenture, including, among others:

•

changing the stated maturity for any principal or interest payment on a debt security;

•

reducing the principal amount, the amount payable on acceleration of the maturity after a default, the interest rate or the redemption price for a debt security;

•

permitting redemption of a debt security if not previously permitted;

•

impairing any right a holder may have to require purchase of its debt security;

•

impairing any right that a holder of convertible debt security may have to convert the debt security;

•

changing the currency of any payment on a debt security;

•

changing the place of payment on a debt security;

•

impair a holder’s right to sue for payment of any amount due on its debt security;

•

release of any guarantor of a debt security from any of its obligations under its guarantee thereof, except in accordance with the terms of the indenture;

•

reducing the percentage in principal amount of the debt securities of any one or more affected series, taken separately or together, as applicable, and whether comprising the same or different series or less than all of the debt securities of a series, the approval of whose holders is needed to change the indenture or those debt securities or waive our compliance with the applicable indenture or to waive defaults; and

•

changing the provisions of the applicable indenture dealing with modification and waiver in any other respect, except to increase any required percentage referred to above or to add to the provisions that cannot be changed or waived without approval of the holder of each affected debt security.

Changes Not Requiring Approval. The second type of change does not require any approval by holders of the debt securities affected. These changes are limited to clarifications and changes that would not adversely affect any debt securities of any series in any material respect. Nor do we need any approval to make changes that affect only debt securities to be issued under the applicable indenture after the changes take effect. We may also make changes or obtain waivers that do not adversely affect a particular debt security, even if they affect other debt securities. In those cases, we do not need to obtain the approval of the holder of the unaffected debt security; we need only obtain any required approvals from the holders of the affected debt securities. We may also make changes to reflect the addition of, succession to or release of any guarantor of guaranteed debt securities otherwise permitted under the indenture. We may also make changes to conform the text of the applicable indenture or any debt securities or guarantees to any provision of the “Description of Debt Securities and Guarantees” in this prospectus or the comparable section in your prospectus supplement, to the extent such provision was intended to be a verbatim recitation of a provision of such indenture or debt securities or guarantees.

Modification of Subordination Provisions. We may not amend the indenture related to subordinated debt securities to alter the subordination of any outstanding subordinated debt securities without the written consent of each holder of senior debt then outstanding who would be adversely affected (or the group or representative thereof authorized or required to consent thereto pursuant to the instrument creating or evidencing, or pursuant to which there is outstanding, such senior debt). In addition, we may not modify the subordination provisions of the indenture related to subordinated debt securities in a manner that would adversely affect the subordinated debt securities of any one or more series then outstanding in any material respect, without the consent of the holders of a majority in aggregate principal amount of all affected series then outstanding, voting together as one class (and also of any affected series that by its terms is entitled to vote separately as a series, as described below).

Changes Requiring Majority Approval. Any other change to a particular indenture and the debt securities issued under that indenture would require the following approval:

•

If the change affects only particular debt securities within a series issued under the applicable indenture, it must be approved by the holders of a majority in principal amount of such particular debt securities; or

•

If the change affects debt securities of more than one series issued under the applicable indenture, it must be approved by the holders of a majority in principal amount of all debt securities of all such series affected by the change, with all such affected debt securities voting together as one class for this purpose and such affected debt securities of any series potentially comprising fewer than all debt securities of such series,

in each case, except as may otherwise be provided pursuant to such indenture for all or any particular debt securities of any series. This means that modification of terms with respect to certain securities of a series could be effectuated without obtaining the consent of the holders of a majority in principal amount of other securities of such series that are not affected by such modification.

The same majority approval would be required for us to obtain a waiver of any of our covenants in either indenture. Our covenants include the promises we make about merging or selling substantially all of our assets, which we describe above under “— Mergers and Similar Transactions.” If the holders approve a waiver of a covenant, we will not have to comply with it. The holders, however, cannot approve a waiver of any provision in a particular debt security, or in the applicable indenture as it affects that debt security, that we cannot change without the approval of the holder of that debt security as described above in “— Changes Requiring Each Holder’s Approval,” unless that holder approves the waiver.

We may issue particular debt securities or a particular series of debt securities, as applicable, that are entitled, by their terms, to separately approve matters (for example, modification or waiver of provisions in the applicable indenture) that would also, or otherwise, require approval of holders of a majority in principal amount of all affected debt securities of all affected series issued under such indenture voting together as a single class. Any such affected debt securities or series of debt securities would be entitled to approve such matters (a) pursuant to such special rights by consent of holders of a majority in principal amount of such affected debt securities or series of debt securities voting separately as a class and (b) in addition, as described above, except as may otherwise be provided pursuant to the applicable indenture for such debt securities or series of debt securities, by consent of holders of a majority in principal amount of such affected debt securities or series of debt securities and all other affected debt securities of all series issued under such indenture voting together as one class for this purpose. We may issue series or debt securities of a series having these or other special voting rights without obtaining the consent of or giving notice to holders of outstanding debt securities or series.

Book-entry and other indirect owners should consult their banks or brokers for information on how approval may be granted or denied if we seek to change an indenture or any debt securities or request a waiver.

Special Rules for Action by Holders

Only holders of outstanding debt securities of the applicable series will be eligible to take any action under the applicable indenture, such as giving a notice of default, declaring an acceleration, approving any change or waiver or giving the trustee an instruction with respect to debt securities of that series. Also, we will count only outstanding debt securities in determining whether the various percentage requirements for taking action have been met. Any debt securities owned by us or any of our affiliates or surrendered for cancellation or for payment or redemption of which money has been set aside in trust are not deemed to be outstanding. Any required approval or waiver must be given by written consent.

In some situations, we may follow special rules in calculating the principal amount of debt securities that are to be treated as outstanding for the purposes described above. This may happen, for example, if the principal amount is payable in a non-U.S. dollar currency, increases over time or is not to be fixed until maturity.

We will generally be entitled to set any day as a record date for the purpose of determining the holders that are entitled to take action under either indenture. In certain limited circumstances, only the trustee will be entitled to set a record date for action by holders. If we or the trustee sets a record date for an approval or other action to

be taken by holders, that vote or action may be taken only by persons or entities who are holders on the record date and must be taken during the period that we specify for this purpose, or that the trustee specifies if it sets the record date. We or the trustee, as applicable, may shorten or lengthen this period from time to time. This period, however, may not extend beyond the 180th day after the record date for the action. In addition, record dates for any global debt security may be set in accordance with procedures established by the depositary from time to time. Accordingly, record dates for global debt securities may differ from those for other debt securities.

Form, Exchange and Transfer

If any debt securities cease to be issued in registered global form, they will be issued:

•

only in fully registered form;

•

without interest coupons; and

•

unless we indicate otherwise in your prospectus supplement, in denominations of $2,000 and integral multiples of $1,000 in excess thereof.

Holders may exchange their debt securities for debt securities of smaller denominations or combined into fewer debt securities of larger denominations, as long as the total principal amount is not changed. You may not exchange your debt securities for securities of a different series or having different terms, unless your prospectus supplement says you may.

Holders may exchange or transfer their debt securities at the office of the trustee. They may also replace lost, stolen, destroyed or mutilated debt securities at that office. We have appointed the trustee to act as our agent for registering debt securities in the names of holders and transferring and replacing debt securities. We may appoint another entity to perform these functions or perform them ourselves.

Holders will not be required to pay a service charge to transfer or exchange their debt securities, but they may be required to pay for any tax or other governmental charge associated with the exchange or transfer. The transfer or exchange, and any replacement, will be made only if our transfer agent is satisfied with the holder’s proof of legal ownership. The transfer agent may require an indemnity before replacing any debt securities.

If we have designated additional transfer agents for your debt security, they will be named in your prospectus supplement. We may appoint additional transfer agents or cancel the appointment of any particular transfer agent. We may also approve a change in the office through which any transfer agent acts.

If the debt securities of any series are redeemable and we redeem less than all those debt securities, we may block the transfer or exchange of those debt securities during the period beginning 15 days before the day we mail the notice of redemption and ending on the day of that mailing, in order to freeze the list of holders to prepare the mailing. We may also refuse to register transfers of or exchange any debt security selected for redemption, except that we will continue to permit transfers and exchanges of the unredeemed portion of any debt security being partially redeemed.

If a debt security is issued as a global debt security, only DTC or other depositary will be entitled to transfer and exchange the debt security as described in this subsection, since the depositary will be the sole holder of the debt security.

The rules for exchange described above apply to exchange of debt securities for other debt securities of the same series and kind. If a debt security is convertible, exercisable or exchangeable into or for a different kind of security, such as one that we have not issued, or for other property, the rules governing that type of conversion, exercise or exchange will be described in the applicable prospectus supplement.

Payments

We will pay interest, principal and other amounts payable with respect to the debt securities of any series to the holders of record of those debt securities as of the record dates and otherwise in the manner specified below or in the prospectus supplement for that series.

We will make payments on a global debt security in accordance with the applicable policies of the depositary as in effect from time to time. Under those policies, we will pay directly to the depositary, or its nominee, and not to any indirect owners who own beneficial interests in the global debt security. An indirect owner’s right to receive those payments will be governed by the rules and practices of the depositary and its participants.

We will make payments on a debt security in non-global, registered form as follows. We will pay interest that is due on an interest payment date by check mailed on the interest payment date to the holder at his or her address shown on the trustee’s records as of the close of business on the regular record date. We will make all other payments by check at the paying agent described below, against surrender of the debt security. All payments by check will be made in next-day funds — i.e., funds that become available on the day after the check is cashed.

Alternatively, if a non-global debt security has a face amount of at least $1,000,000 and the holder asks us to do so, we will pay any amount that becomes due on the debt security by wire transfer of immediately available funds to an account at a bank in New York City, on the due date. To request wire payment, the holder must give the paying agent appropriate wire transfer instructions at least five business days before the requested wire payment is due. In the case of any interest payment due on an interest payment date, the instructions must be given by the person or entity who is the holder on the relevant regular record date. In the case of any other payment, payment will be made only after the debt security is surrendered to the paying agent. Any wire instructions, once properly given, will remain in effect unless and until new instructions are given in the manner described above.

Book-entry and other indirect owners should consult their banks or brokers for information on how they will receive payments on their debt securities.

Regardless of who acts as paying agent, all money paid by us to a paying agent that remains unclaimed at the end of two years after the amount is due to a holder will be repaid to us. After that two-year period, the holder may look only to us for payment and not to the trustee, any other paying agent or anyone else.

Guarantees

The debt securities of any series may be guaranteed by one or more of our subsidiaries. However, the applicable indenture governing the debt securities will not require that any of our subsidiaries be a guarantor of any series of debt securities and will permit the guarantors for any series of guaranteed debt securities to be different from any of the subsidiaries listed above under “— General.” As a result, a series of debt securities may not have any guarantors and the guarantors of any series of guaranteed debt securities may differ from the guarantors of any other series of guaranteed debt securities. If we issue a series of guaranteed debt securities, the identity of the specific guarantors of the debt securities of that series will be identified in the applicable prospectus supplement.

If we issue a series of guaranteed debt securities, a description of some of the terms of guarantees of those debt securities will be set forth in the applicable prospectus supplement. Unless otherwise provided in the prospectus supplement relating to a series of guaranteed debt securities, each guarantor of the debt securities of such series will unconditionally guarantee the due and punctual payment of the principal of, and premium, if any, and interest, if any, on each debt security of such series, all in accordance with the terms of such debt securities and the applicable indenture.

Notwithstanding the foregoing, unless otherwise provided in the prospectus supplement relating to a series of guaranteed debt securities, the applicable indenture will contain provisions to the effect that the obligations of each guarantor under its guarantees and such indenture shall be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities of such guarantor, result in the obligations of such guarantor under such guarantees and such indenture not constituting a fraudulent conveyance or fraudulent transfer under applicable law. However, there can be no assurance that, notwithstanding such limitation, a court would not determine that a guarantee constituted a fraudulent conveyance or fraudulent transfer under applicable law. If that were to occur, the court could void the applicable guarantor’s obligations under that guarantee, subordinate that guarantee to other debt and other liabilities of that guarantor or take other action detrimental to holders of the debt securities of the applicable series, including directing the holders to return any payments received from the applicable guarantor.

Unless otherwise provided in the prospectus supplement relating to a series of guaranteed debt securities, the applicable indenture will (i) provide that, upon the sale or disposition (by merger or otherwise) of any guarantor, (x) if the transferee is not an affiliate of us, such guarantor will automatically be released from all obligations under its guarantee of such debt securities or (y) otherwise, the transferee (if other than us or another guarantor) will assume the guarantor’s obligations under its guarantee of such debt securities and (ii) permit us to cause the guarantee of any guarantor of such debt securities to be released at any time if we satisfy such conditions, if any, as are specified in the prospectus supplement for such debt securities.

The applicable prospectus supplement relating to any series of guaranteed debt securities will specify other terms of the applicable guarantees.

If the applicable prospectus supplement relating to a series of our senior debt securities provides that those senior debt securities will have the benefit of a guarantee by any or all of our subsidiaries, unless otherwise provided in the applicable prospectus supplement, each such guarantee will be the unsubordinated and unsecured obligation of the applicable guarantor and will rank equally in right of payment with all of the unsecured and unsubordinated indebtedness of such guarantor.

Any guarantee of any debt securities will be effectively subordinated to all existing and future secured indebtedness of the applicable guarantor, including any secured guarantees of other Company debt, to the extent of the value of the collateral securing that indebtedness. Consequently, in the event of a bankruptcy, or similar proceeding with respect to any guarantor that has provided a guarantee of any debt securities, the holders of that guarantor’s secured indebtedness will be entitled to proceed directly against the collateral that secures that secured indebtedness and such collateral will not be available for satisfaction of any amount owed by such guarantor under its unsecured indebtedness, including its guarantees of any debt securities, until that secured debt is satisfied in full. Unless otherwise provided in the applicable prospectus supplement, the indenture will not limit the ability of any guarantor to incur secured indebtedness.

If the applicable prospectus supplement relating to a series of our subordinated debt securities provides that those subordinated debt securities will have the benefit of a guarantee by any or all of our subsidiaries, unless otherwise provided in the applicable prospectus supplement, each such guarantee will be the subordinated and unsecured obligation of the applicable guarantor and, in addition to being effectively subordinated to secured debt of such guarantor, will be subordinated in right of payment to all of such guarantor’s existing and future senior indebtedness, including any guarantee of the senior debt securities, to the same extent and in the same manner as the subordinated debt securities are subordinated to our senior debt. See “— Subordination Provisions” above.

Paying Agents

We may appoint one or more financial institutions to act as our paying agents, at whose designated offices debt securities in non-global entry form may be surrendered for payment at their maturity. We call each of those offices a paying agent. We may add, replace or terminate paying agents from time to time. We may also choose

to act as our own paying agent. We will specify in the prospectus supplement for your debt security the initial location of each paying agent for that debt security. We must notify the trustee of changes in the paying agents.

Notices

Notices to be given to holders of a global debt security will be sufficiently given if given to the depositary, in accordance with its applicable policies as in effect from time to time. Notices to be given to holders of debt securities not in global form will be sent by mail to the respective addresses of the holders as they appear in the trustee’s records, and will be deemed given when mailed. Neither the failure to give any notice to a particular holder, nor any defect in a notice given to a particular holder, will affect the sufficiency of any notice given to another holder.

Book-entry and other indirect owners should consult their banks or brokers for information on how they will receive notices.

Our Relationship With the Trustee

The prospectus supplement for your debt security will describe any material relationships we may have with the trustee with respect to that debt security.

The same financial institution may initially serve as the trustee for our senior debt securities and subordinated debt securities. Consequently, if an actual or potential event of default occurs with respect to any of these securities, the trustee may be considered to have a conflicting interest for purposes of the Trust Indenture Act of 1939. In that case, the trustee may be required to resign under one or more of the indentures, and we would be required to appoint a successor trustee. For this purpose, a “potential” event of default means an event that would be an event of default if the requirements for giving us default notice or for the default having to exist for a specific period of time were disregarded.

Warrants to Purchase Debt Securities

We may issue warrants for the purchase of the debt securities. Such warrants may be issued independently or together with other securities and may be attached to or separate from any offered securities. Each series of warrants for the purchase of debt securities will be issued under a separate warrant agreement to be entered into between us and a bank or trust company, as warrant agent. The warrant agent will act solely as our agent in connection with the warrants and will not have any obligation or relationship of agency or trust for or with any holders or beneficial owners of warrants. A copy of the warrant agreement will be filed with the Commission in connection with the offering of warrants.

The prospectus supplement relating to a particular issue of warrants to purchase debt securities will describe the terms of such warrants, including, among other things, the following:

•

the title of the warrants to purchase debt securities;

•

the offering price for the warrants to purchase debt securities, if any;

•

the aggregate number of the warrants to purchase debt securities;

•

the designation, aggregate principal amount, currencies, denominations and other terms of the series of debt securities purchasable upon exercise of the warrants to purchase debt securities and the price at which such debt securities may be purchased upon such exercise;

•

if applicable, the designation and terms of the securities that the warrants to purchase debt securities are issued with and the number of warrants to purchase debt securities issued with each such security;

•

if applicable, the date from and after which the warrants and any securities issued with the warrants will be separately transferable;

•

the dates on which the right to exercise the warrants to purchase debt securities commence and expire;

•

if applicable, the minimum or maximum amount of the warrants to purchase debt securities that may be exercised at any one time;

•

the currency or currency units in which the offering price, if any, and the exercise price are payable;

•

if applicable, a discussion of material federal income tax considerations;

•

redemption or call provisions, if any, applicable to the warrants to purchase debt securities;

•

any additional terms of the warrants to purchase debt securities, including terms, procedures, and limitations relating to the exercise of the warrants to purchase debt securities; and

•

any other information we think is important about the warrants to purchase debt securities.

Each warrant will entitle the holder of the warrant to purchase such principal amount of debt securities being offered at the exercise price set forth in the applicable prospectus supplement. Holders may exercise warrants to purchase debt securities at any time up to the close of business on the expiration date set forth in the applicable prospectus supplement. After the close of business on the expiration date, unexercised warrants to purchase debt securities are void. Holders may exercise warrants to purchase debt securities as set forth in the prospectus supplement relating to the warrants to purchase debt securities being offered.

Until you exercise your warrants to purchase debt securities, you will not have any rights as a holder of debt securities, including the right to receive payments of principal of, premium, if any, or interest, if any, on the debt securities purchasable upon such exercise or to enforce covenants in the applicable indenture, by virtue of your ownership of such warrants.

MATERIAL INCOME TAX CONSEQUENCES

This section is a discussion of the material income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, expresses the opinion of Akin Gump Strauss Hauer & Feld LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury Regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “Genesis,” “us,” “we,” “our,” or “ours” are references to Genesis Energy, L.P. and its subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Akin Gump Strauss Hauer & Feld LLP and are based on the accuracy of the representations made by us and our general partner. No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions and advice of Akin Gump Strauss Hauer & Feld LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne directly or indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion with respect to the following specific federal income tax issues:

(1)

the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please see “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

(2)

whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please see “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and

(3)

whether our method for depreciating Section 743 adjustments is sustainable (please see “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to

him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or to the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof and fertilizer. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that at least 90% of our current gross income is qualifying income. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Akin Gump Strauss Hauer & Feld LLP is of the opinion that at least 90% of our current gross income should constitute qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status as a partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Akin Gump Strauss Hauer & Feld LLP. It is the opinion of Akin Gump Strauss Hauer & Feld LLP that, based upon the Internal Revenue Code, the Treasury Regulations, published revenue rulings and court decisions and the representations described below, we should be classified as a partnership for federal income tax purposes.

In rendering its opinion, Akin Gump Strauss Hauer & Feld LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which counsel has relied include:

(a)

Neither we nor the operating company has elected or will elect to be treated as a corporation;

(b)

For each taxable year, more than 90% of our gross income has been and will be income from sources that Akin Gump Strauss Hauer & Feld LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

(c)

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to our unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable

dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Any modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact an investment in our common units. In addition, 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, in 2008, we began paying Texas franchise tax at a maximum effective rate of 0.5% of our gross income apportioned to Texas in the prior year.

The remainder of the discussion below is based on Akin Gump Strauss Hauer & Feld LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Genesis will be treated as partners of Genesis for federal income tax purposes. Also:

(a)

assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

(b)

unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of Genesis for federal income tax purposes. As there is no direct authority addressing assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Akin Gump Strauss Hauer & Feld LLP does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please see “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Genesis.

The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Genesis for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income. Except for taxes paid by our corporate subsidiaries, we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of our common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please see “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount of cash he pays for our common units and his adjusted basis in any assets he exchanges for common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please see “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations), to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholders’ tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

•

interest on indebtedness properly allocable to property held for investment;

•

our interest expense attributed to portfolio income; and

•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Payments. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the

priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. If we have a net loss, that loss will be allocated to our unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in an offering will be essentially the same as if the tax bases of our assets were equal to their fair market value at the time of such offering. In the event we issue additional common units or engage in certain other transactions in the future, we will make “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, to all holders of partnership interests immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner as is needed to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•

his relative contributions to us;

•

the interests of all the partners in profits and losses;

•

the interest of all the partners in cash flow; and

•

the rights of all the partners to distributions of capital upon liquidation.

Akin Gump Strauss Hauer & Feld LLP is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

•

any cash distributions received by the unitholder as to those units would be fully taxable; and

•

all of these distributions would appear to be ordinary income.

Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units because there is no direct or indirect authority on the issue related to partnership interests and without such authority a legal opinion cannot be issued; therefore, 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 modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 20%. These rates are subject to change by new legislation at any time.

A 3.8% Medicare tax on certain investment income earned by individuals, estates and trusts applies for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net income from all investments, and (ii) the amount by which the unitholder’s adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filed separately) or $200,000 (if the unitholder is single or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Where the remedial allocation method is adopted (which we have generally adopted as to all of our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the Section 704(c) built in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please see “— Uniformity of Units.”

Although Akin Gump Strauss Hauer & Feld LLP is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please see “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please see “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes

of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please see “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our unitholders holding interests in us prior to any such offering. Please see “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. We may not be entitled to amortization deductions with respect to certain goodwill conveyed to us in future transactions or held at the time of any future offering. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please see “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;

•

an offsetting notional principal contract; or

•

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among our unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be

allocated among our unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Akin Gump Strauss Hauer & Feld LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale. A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination. We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders may receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. However, pursuant to an IRS relief procedure for publicly traded partnerships that have technically terminated, the IRS may allow, among other things, that we provide a single Schedule K-1 for the tax year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please see “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the Treasury Regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please see “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable methods and lives as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on our unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on our unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please see “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raise issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or other disposition of units. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will in all cases yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Akin Gump Strauss Hauer & Feld LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement gives our board of directors the authority to designate a Tax Matters Partner.

The Tax Matters Partner has made and will make elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all our unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on the tax report we provide to him. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a)

the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b)

whether the beneficial owner is

(1)

a person that is not a United States person,

(2)

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

(3)

a tax-exempt entity;

(c)

the amount and description of units held, acquired or transferred for the beneficial owner; and

(d)

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1)

for which there is, or was, “substantial authority,” or

(2)

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in

any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please see “— Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties,”

•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

•

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

State, Local, Foreign and Other Tax Consequences

In addition to federal income taxes, you may be subject to other taxes, such as state, local, and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We own assets and do business in more than 25 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and Oklahoma. Many of the states we currently do business in currently impose a personal income tax. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder is urged to consider their potential impact on his investment in us. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you might be required to file income tax returns and to pay income taxes in other jurisdictions in which we do business or own property, now or in the future, and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please see “— Tax Consequences of Unit Ownership — Entity-Level Payments.”

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Akin Gump Strauss Hauer & Feld LLP has not rendered an opinion on the state, local, or foreign tax consequences of an investment in us.

INVESTMENT IN GENESIS BY EMPLOYEE BENEFIT PLANS AND IRAs

IRS Circular 230 Notice Requirement. This communication is not given in the form of a covered opinion, within the meaning of Circular 230 issued by the United States Secretary of the Treasury. Thus, we are required to inform you that you cannot rely upon any tax advice contained in this communication for the purpose of avoiding United States federal tax penalties. In addition, any tax advice contained in this communication may not be used to promote, market or recommend a transaction to another party.

The following is a summary of certain considerations associated with an investment in our securities by any employee benefit plan that is subject to Title I of the U.S. Employee Retirement Income Security Act of 1974, as amended (“ERISA”), any plan, individual retirement account (an “IRA”) or other arrangement that is subject to Section 4975 of the Internal Revenue Code or provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Internal Revenue Code (collectively, “Similar Laws”), and any entity whose underlying assets are considered to include “plan assets” by reason of any such plan’s, account’s or arrangement’s investment in such entity (each of the foregoing, a “Plan”). This summary is based on the provisions of ERISA and the Internal Revenue Code, and the related regulations and administrative and judicial interpretations, as of the date hereof. This summary does not purport to be complete, and no assurance can be given that future legislation, court decisions or administrative regulations, rulings or pronouncements will not significantly modify the requirements summarized herein. Any such changes may be retroactive and thereby apply to transactions entered into before the date of their enactment or release.

General Fiduciary Matters

ERISA and the Internal Revenue Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Internal Revenue Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Internal Revenue Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in Genesis of a portion of the assets of any Plan, a fiduciary should determine whether the investment is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Internal Revenue Code or any Similar Law relating to a fiduciary’s duties to the Plan including, without limitation, the prudence, diversification, delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

Any insurance company proposing to invest assets of its general account in our securities should consider the extent that the investment would be subject to the requirements of ERISA in light of the U.S. Supreme Court’s decision in John Hancock Mutual Life Insurance v. Harris Trust and Savings Bank, 114 S.Ct. 517 (1993), which in certain circumstances treats those general account assets as assets of an ERISA Plan for purposes of the fiduciary responsibility provisions of ERISA and the prohibited transaction provisions of ERISA and the Internal Revenue Code. In addition, such potential investor should consider the effect of any subsequent legislation or other guidance that has or may become available relating to that decision, including Section 401(c) of ERISA and the regulations thereunder.

Prohibited Transactions

Section 406 of ERISA and Section 4975 of the Internal Revenue Code (which also applies to IRAs of individuals) prohibit ERISA Plans from engaging in specified transactions involving “plan assets” with persons or entities who are “parties in interest” under ERISA or “disqualified persons” under Section 4975 of the Internal Revenue Code, unless an exemption is available. A party in interest or disqualified person who engaged in a non-

exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA Plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

The acquisition or holding of our securities by an ERISA Plan with respect to which either we, our general partner, selling unitholders or any of their respective affiliates is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA or Section 4975 of the Internal Revenue Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption. In this regard, the United States Department of Labor (the “DOL”) has issued prohibited transaction class exemptions, or “PTCEs,” that may apply to the acquisition and holding of the common units. These class exemptions include, without limitation, PTCE 75-1, which exempts certain transactions between an ERISA Plan and certain broker-dealers, reporting dealers and banks, PTCE 84-14 respecting transactions determined by independent qualified professional asset managers, PTCE 90-1 respecting insurance company pooled separate accounts, PTCE 91-38 respecting bank collective investment funds, PTCE 95-60 respecting life insurance company general accounts and PTCE 96-23 respecting transactions determined by in-house asset managers, although there can be no assurance that all of the conditions of any such exemptions will be satisfied. In addition, the statutory service provider exemption provided by Section 408(b)(17) of ERISA and Section 4975(d)(20) of the Internal Revenue Code, which exempts certain transactions between ERISA Plans and parties in interest or disqualified persons that are not fiduciaries with respect to the transaction could apply.

We cannot provide any assurance that any of these class exemptions or statutory exemptions will apply with respect to any particular investment in our securities by, or on behalf of, an ERISA Plan or, even if it were deemed to apply, that any exemption would apply to all transactions that may occur in connection with the investment.

Because of the foregoing, our securities should not be purchased or held by any person investing “plan assets” of any Plan, unless such purchase and holding will not constitute or result in a non-exempt prohibited transaction under ERISA and the Internal Revenue Code or a violation of any applicable Similar Laws. Each person investing in Genesis will be deemed to represent that its acquisition, holding and disposition of such investment will not constitute a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Internal Revenue Code.

Plan Asset Issues

The DOL as adopted regulations (the “Plan Asset Regulations”) that generally provide that when an ERISA Plan invests in an equity interest of an entity that is neither a “publicly-offered security” nor a security issued by an investment company registered under the Investment Company Act of 1940, the ERISA Plan’s assets include both the equity interest and an undivided interest in each of the underlying assets of the entity (the “look-through rule”), unless it is established either that equity participation in the entity by “benefit plan investors” is not “significant” or that the entity is an “operating company,” in each case as defined in the Plan Asset Regulations. Section 3(42) of ERISA defines the term “plan assets” to mean plan assets as defined by such regulations as the DOL may prescribe, except that under such regulations the assets of an entity shall not be treated as plan assets if, immediately after the most recent acquisition of an equity interest in the entity, less than 25% of the total value of each class of equity interest in the entity is held by Benefit Plan Investors. The term “Benefit Plan Investor” means any employee benefit plan subject to the fiduciary provisions of ERISA, any plan, IRA or other arrangement to which the prohibited transaction provisions of Section 4975 of the Internal Revenue Code apply and any entity whose underlying assets include plan assets by reason of a plan’s investment in such entity.

Except as specifically addressed by Section 3(42) of ERISA, until the DOL issues regulations under Section 3(42) of ERISA, it is probable that the principles set forth in the Plan Asset Regulations will continue to apply with respect to determinations as to whether an entity’s underlying assets include plan assets, including the

general exception to the look-through rule for operating companies. The Plan Asset Regulations define an “operating company” in part as an entity that is primarily engaged, directly or through a majority owned subsidiary or subsidiaries, in the production or sale of a product or service other than the investment of capital.

Plan Asset Consequences

If our assets were deemed to be “plan assets” under ERISA, it would result, among other things, in (i) the application of the prudence and other fiduciary responsibility standards of ERISA to investments made by us and (ii) the possibility that certain transactions in which we might seek to engage could constitute “prohibited transactions” under ERISA and the Internal Revenue Code. (Whether or not our assets are deemed to be “plan assets” under ERISA, see discussion under “Prohibited Transactions” above).

It is not anticipated that our assets will be considered plan assets because we are primarily engaged in business activities that we believe qualify us as an “operating company” under the Plan Asset Regulations (although no assurance can be given in this regard). In addition, because our common units are “publicly-offered securities” and our debt securities are not “equity interests” for purposes of the Plan Asset Regulations, even significant investment by Benefit Plan Investors in those securities would not result in our assets being treated as plan assets under ERISA. Investment in each class of our securities by Benefit Plan Investors also may not be “significant” for purposes of the Plan Asset Regulations, although it is unlikely that we will be in a position to monitor whether or not investment in any class of our securities by Benefit Plan Investors is or may become significant.

The foregoing discussion is general in nature and is not intended to be all-inclusive. Due to the complexity of these rules and the penalties that may be imposed on persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries or other persons considering purchasing the common units on behalf of, or with the assets of, any Plan, consult with their own counsel regarding the potential applicability of ERISA, Section 4975 of the Internal Revenue Code and any Similar Laws to such investment and whether an exemption would be applicable to the purchase and holding of the common units.

PLAN OF DISTRIBUTION

We may offer and sell the securities described in this prospectus from time to time directly, through agents, or to or through underwriters or dealers. The prospectus supplement relating to any particular offering will contain the terms of the securities sold in that offering, including:

•

the names of any underwriters, dealers or agents (if any);

•

the offering price;

•

underwriting discounts;

•

sales agents’ commissions;

•

other forms of underwriter or agent compensation;

•

discounts, concessions or commissions that underwriters may pass on to other dealers; and

•

any exchange on which the securities are listed.

We may change the offering price, underwriting discounts or concessions, or the price to dealers when necessary. Discounts or commissions received by underwriters or agents and any profits on the resale of securities by them may constitute underwriting discounts and commissions under the Securities Act of 1933, as amended (the “Securities Act”).

Unless we state otherwise in a prospectus supplement, underwriters will need to meet certain requirements before purchasing securities. Agents may act on a “best efforts” basis during their appointment. We will also state the net proceeds from the sale in a prospectus supplement.

Any brokers or dealers that participate in the distribution of the securities may be “underwriters” within the meaning of the Securities Act for such sales. Profits, commissions, discounts or concessions received by such broker or dealer may be underwriting discounts and commissions under the Securities Act. Brokers or dealers may act as agent or may purchase securities as principal and thereafter resell the securities from time to time in or through one or more transactions or distributions.

Offers to purchase securities may be solicited directly by us and the sale thereof may be made by us directly to institutional investors or others, who may be deemed to be underwriters within the meaning of the Securities Act with respect to any resale thereof. The terms of any such sales will be described in the prospectus supplement relating thereto. We may use electronic media, including the Internet, to sell offered securities directly.

When necessary, we may fix securities distributions using changeable, fixed prices, market prices at the time of sale, prices related to market prices, or negotiated prices.

We may, through agreements, indemnify underwriters, dealers or agents that participate in the distribution of the securities against certain liabilities including liabilities under the Securities Act. We may also provide funds for payments that the underwriters, dealers or agents may be required to make. Underwriters, dealers and agents, and their affiliates may transact with us and our affiliates in the ordinary course of their business.

We may offer our equity securities described in this prospectus into an existing trading market on the terms described in the prospectus supplement thereto. Underwriters and dealers who may participate in any at-the-market offerings will be described in the prospectus supplement relating thereto.

The aggregate maximum compensation the underwriters will receive in connection with the sale of any securities under this prospectus and the registration statement of which it forms a part will not exceed 10% of the gross proceeds from the sale.

Because the Financial Industry Regulatory Authority (FINRA) views our common units as interests in a direct participation program, any offering of common units under the registration statement of which this prospectus forms a part will be made in compliance with Rule 2310 of the FINRA Rules.

To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution. The place and time of delivery for the equity securities in respect of which this prospectus is delivered will be set forth in the accompanying prospectus supplement.

To facilitate an offering of a series of the securities, certain persons participating in the offering may engage in transactions that stabilize, maintain, or otherwise affect the price of the securities. This may include over-allotments or short sales of the securities, which involves the sale by persons participating in the offering of more securities than we sold to them. In these circumstances, these persons would cover the over-allotments or short positions by making purchases in the open market or by exercising their over-allotment option. In addition, these persons may stabilize or maintain the price of the securities by bidding for or purchasing securities in the open market or by imposing penalty bids, whereby selling concessions allowed to dealers participating in the offering may be reclaimed if securities sold by them are repurchased in connection with stabilization transactions. The effect of these transactions may be to stabilize or maintain the market price of the securities at a level above that which might otherwise prevail in the open market. These transactions may be discontinued at any time.

Any offering and sale under this prospectus may be made on one or more national securities exchanges or in the over-the-counter market, or otherwise at prices and on terms then prevailing or at prices related to the then-current market price, or in negotiated transactions.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

The statements in this prospectus or incorporated by reference into this prospectus that are not historical information may be “forward-looking statements” as defined under federal law.

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throughput levels and rates;

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changes in, or challenges to, our tariff rates;

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our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

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service interruptions in our pipeline transportation systems and processing operations;

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shutdowns or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum or other products or to whom we sell such products;

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risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;

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changes in laws and regulations to which we are subject, including tax withholding issues, accounting pronouncements, and safety, environmental and employment laws and regulations;

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the effects of production declines and the effects of future laws and government regulation;

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planned capital expenditures and availability of capital resources to fund capital expenditures;

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our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants;

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loss of key personnel;

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an increase in the competition that our operations encounter;

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cost and availability of insurance;

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hazards and operating risks that may not be covered fully by insurance;

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our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flows;

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changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;

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natural disasters, accidents or terrorism;

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changes in the financial condition of customers or counterparties;

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adverse rulings, judgments, or settlements in litigation or other legal or tax matters;

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the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and

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LEGAL MATTERS

The validity of the securities offered in this prospectus as well as the legal matters described under “Material Income Tax Consequences” will be passed upon for us by Akin Gump Strauss Hauer & Feld LLP. The validity of certain of the offered securities and other matters arising under Alabama and Louisiana law will be passed upon by McDavid, Noblin & West PLLC and Liskow & Lewis, A Professional Law Corporation, respectively. Any underwriter will be advised about other issues relating to any offering by its own legal counsel.

EXPERTS

The consolidated financial statements incorporated in this prospectus by reference from Genesis Energy, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2014 and the effectiveness of Genesis Energy, L.P. and subsidiaries’ internal control over financial reporting have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein by reference. Such consolidated financial statements have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and other reports and other information with the Commission. You may read and copy documents we file at the Commission’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the Commission at 1-800-SEC-0330 for information on the public reference room. You can also find our filings at the Commission’s website at http://www.sec.gov and on our website at http://www.genesisenergy.com. We make our website content available for information purposes only. Information contained on our website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

The Commission allows us to “incorporate by reference” the information we have filed with the Commission, which means that we can disclose important information to you without actually including the specific information in this prospectus by referring you to those documents. The information incorporated by reference is an important part of this prospectus and later information that we file with the Commission will automatically update and supersede this information. Therefore, before you decide to invest in a particular offering under this shelf registration, you should always check for reports we may have filed with the Commission after the date of this prospectus. We incorporate by reference the documents listed below and any future filings we make with the Commission under Sections 13(a), 13(c), 14, or 15(d) of the Exchange Act (excluding information deemed to be furnished and not filed with the Commission) until we sell all of the securities offered by this prospectus:

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Annual Report on Form 10-K for the fiscal year ended December 31, 2014; and

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the description of our common units in our registration statements on Form 8-A (File No. 001-12295) filed on January 30, 2001 and September 13, 2010, and any subsequent amendment thereto filed for the purpose of updating such description.

We will provide without charge to each person, including any beneficial owner, to whom this prospectus is delivered, upon written or oral request, a copy of any document incorporated by reference in this prospectus, other than exhibits to any such document not specifically described above. Requests for such documents should be directed to:

Investor Relations

Genesis Energy, L.P.

919 Milam, Suite 2100

Houston, Texas 77002

(713) 860-2500 or (800) 284-3365

We intend to furnish or make available to our unitholders within 75 days (or such shorter period as the Commission may prescribe) following the close of our fiscal year end annual reports containing audited financial statements prepared in accordance with generally accepted accounting principles and furnish or make available within 40 days (or such shorter period as the Commission may prescribe) following the close of each fiscal quarter quarterly reports containing unaudited interim financial information, including the information required by Form 10-Q for the first three fiscal quarters of each of our fiscal years. Our annual report will include a description of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, including the amount paid or accrued to each recipient and the services performed.

LOGO

Genesis Energy, L.P.

9,000,000 Common Units

Representing Limited Partner Interests

PRELIMINARY PROSPECTUS SUPPLEMENT

July , 2015

Joint Book-Running Managers


Wells Fargo Securities		BofA Merrill Lynch		Citigroup


Deutsche Bank Securities		Barclays		Credit Suisse		UBS Investment Bank


Raymond James		RBC Capital Markets		BMO Capital Markets

Co-Managers


Oppenheimer & Co.		Baird		Janney Montgomery Scott