UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

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

 

For the fiscal year ended December 31, 2006

 

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from ___ to ___.

 

Commission file number: 1-33266

 

DUNCAN ENERGY PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

 

 

Securities to be registered pursuant to Section 12(g) of the Act: None.

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes o No x

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer o               Accelerated filer o               Non-accelerated filer x

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

 

Duncan Energy Partners L.P. completed its initial public offering of 14,950,000 common units on February 5, 2007. Accordingly, the registrant did not have an aggregate market value of its common units as of the last business day of June 30, 2006. As of March 31, 2007, there were 20,301,571 outstanding common units of Duncan Energy Partners L.P. This figure includes 5,351,571 common units owned by Enterprise Products Operating L.P., the parent company of Duncan Energy Partners L.P.

 

 

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DUNCAN ENERGY PARTNERS L.P.

TABLE OF CONTENTS

 

 

 

 

 

 

 

 

 

 

 

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SIGNIFICANT RELATIONSHIPS REFERENCED IN THIS

ANNUAL REPORT

 

Duncan Energy Partners L.P. did not own any assets prior to February 5, 2007, which was the date it completed its initial public offering of common units. The historical business and operations of Duncan Energy Partners L.P. prior to February 5, 2007 are referred to as “Duncan Energy Partners Predecessor.” Unless the context requires otherwise, references to “we,” “us,” “our,” “the Partnership” or “Duncan Energy Partners” are intended to mean the business and operations of Duncan Energy Partners L.P. and its consolidated subsidiaries since February 5, 2007. When used in a historical context (i.e. prior to February 5, 2007), these terms are intended to mean the combined business and operations of Duncan Energy Partners Predecessor.

 

 

References to “DEP Operating Partnership” mean DEP Operating Partnership L.P., which is a wholly owned subsidiary of Duncan Energy Partners that conducts substantially all of its business.

 

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., which owns Enterprise Products Operating L.P.

 

References to “EPOLP” mean Enterprise Products Operating L.P., which is our parent. EPOLP has a controlling interest in the Partnership’s general partner and is a significant owner of the Partnership’s common units.

 

References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., which owns Enterprise Products GP.

 

References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.

 

References to “TEPPCO” mean TEPPCO Partners, L.P.; a publicly traded Delaware limited partnership, which is an affiliate of us.

 

References to “TEPPCO GP” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and owned by a private company subsidiary of EPCO, Inc.

 

References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities.

 

All of the aforementioned entities are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

 

This annual report contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A of this annual report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary

 

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materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements.

 

PART I

 

Items 1 and 2. Business and Properties.

 

General

 

Duncan Energy Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” We were formed by Enterprise Products Partners in September 2006 to acquire, own and operate a diversified portfolio of midstream energy assets. On February 5, 2007, we completed our initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at a price of $21.00 per unit, which generated net proceeds to us of $291.3 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, we distributed $260.6 million of these net proceeds to EPOLP along with $198.9 million in borrowings under our credit facility and a final amount of 5,351,571 of our common units (after giving the effect to the redemption of 1,950,000 common units).

 

We are owned 98% by our limited partners and 2% by our general partner, DEP GP, which is a wholly owned subsidiary of EPOLP. DEP GP is responsible for managing all of our operations and activities. EPCO provides all employees and certain administrative services for us. Our principle executive offices are located at 1100 Louisiana, 10^th Floor, Houston, Texas 77002 and our telephone number is (713) 381-6500.

 

We are engaged in the business of gathering, transporting, marketing and storing natural gas and transporting and storing natural gas liquids (“NGLs”) and petrochemicals. Prior to completion of our initial public offering on February 5, 2007, our subsidiaries were wholly owned by Enterprise Products Partners. Our subsidiaries will continue to be a part of Enterprise Products Partners’ integrated network of midstream energy assets, or value chain, that includes natural gas gathering, processing, transportation and storage; NGL fractionation (or separation), transportation, storage and import and export terminalling; crude oil transportation; and offshore production platform services.

 

The principal business entities included in the historical combined financial statements of Duncan Energy Partners Predecessor are (on a 100% basis): (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a Delaware limited liability company; (ii) Acadian Gas, LLC (“Acadian Gas”), a Delaware limited liability company; (iii) Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), a Delaware limited partnership, including its general partner; (iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), a Delaware limited partnership, including its general partner; and (v) South Texas NGL Pipelines, LLC (“South Texas NGL”), a Delaware limited liability company. EPOLP contributed a 66% equity interest in each of these five entities to us on February 5, 2007. EPOLP retained the remaining equity interests.

 

The following is a brief description of the operations of each of our businesses, of which 66% of the equity interests of each were contributed to us:

 

 

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Enterprise Products Partners has owned controlling interests and operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years. On February 5, 2007, DEP Operating Partnership (the primary operating subsidiary of the Partnership) assumed these responsibilities. We believe our relationship with Enterprise Products Partners will enable us to maintain stable cash flows and optimize our economies of scale, strategic location and pipeline connections.

 

Business Strategy

 

Our primary business objectives are to maintain and, over time, to increase our cash available for distributions to our unitholders. Our business strategies to achieve these objectives are to:

 

 

 

 

 

Financial Information by Business Segment

 

For information regarding our business segments, please read Note 11 of the Notes to Combined Financial Statements of Duncan Energy Partners Predecessor included under Item 8 of this annual report.

 

Segment Discussion

 

We classify our midstream energy operations in four reportable business segments: NGL & Petrochemical Storage Services, Natural Gas Pipelines & Services, Petrochemical Pipeline Services and NGL Pipeline Services. Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold. A brief description of each business segment follows:

 

 

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capacity of approximately 100 million barrels, and a brine system with approximately 20 million barrels of above ground storage capacity and two brine production wells. These assets receive, store and deliver NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States.

 

 

 

 

One of our principal attributes is our relationship with Enterprise Products Partners and EPCO. Our assets connect to various midstream energy assets of Enterprise Products Partners and, therefore, form integral links within Enterprise Products Partners’ value chain. Enterprise Products Partners is a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, NGLs, crude oil and certain petrochemicals, and is an industry leader in the development of pipeline and other midstream energy infrastructure in the continental United States and Gulf of Mexico. Enterprise Products Partners’ value chain links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States, Canada and the Gulf of Mexico with domestic consumers and international markets. We believe that the operational significance of our assets to Enterprise Products Partners, as well as the alignment of our respective economic interests in these assets, will result in a collaborative effort to promote their operational efficiency and maximize value.

 

All of our and Enterprise Products Partners’ management, administrative and operating functions are performed by employees of EPCO, Enterprise Products Partners’ ultimate parent company under common control by Dan L. Duncan, pursuant to an amended and restated administrative services agreement (see Item 13 of this annual report). Dan L. Duncan and his affiliates have a significant interest in our partnership through EPOLP’s ownership of 34% of the equity interests in our operating subsidiaries and EPOLP’s direct ownership of approximately 26.4% of our outstanding common units and indirect ownership of our 2% general partner interest. We believe our relationship with Enterprise Products Partners and EPCO provides us with a distinct advantage in both the operation of our assets and in the identification and execution of potential future acquisitions that are not otherwise taken by Enterprise Products Partners or Enterprise GP Holdings in accordance with our business opportunity agreements.

 

We are currently engaged in the business of gathering, transporting, marketing, and storing natural gas and transporting and storing NGLs and petrochemicals. Our business is directly impacted by changes in domestic demand for and production of natural gas, NGLs, propylene and other petrochemical products.

 

 

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As generally used in the energy industry and in this document, the identified terms have the following meanings:

 

 

Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration (“EIA”), total annual domestic consumption of natural gas is expected to increase from approximately 22.4 Tcf, or 61.4 Bcf/d, in 2004 to approximately 26.9 Tcf, or 73.7 Bcf/d, in 2030, representing an average annual growth rate of over 1.12% per year. Most of that increase is expected to occur before 2017, when total U.S. natural gas consumption reaches just over 26.5 Tcf. After 2017, rising natural gas prices are predicted to curb consumption growth and reduce the natural gas share of total energy consumption. The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the last three years, these sectors accounted for approximately 56% of the total natural gas consumed in the United States. In 2004, natural gas represented approximately 24% of all end-user domestic energy requirements. During the last five years, the United States has on average consumed approximately 22.4 Tcf per year, with average annual domestic production of approximately 18.9 Tcf during the same period. Driven by growth in natural gas demand and high natural gas prices, domestic natural gas production is projected to increase from 18.5 Tcf per year to 20.4 Tcf per year between 2004 and 2015.

 

Once natural gas is produced from wells, producers seek to deliver the natural gas and its components to end-user markets. The midstream natural gas industry is the link between upstream exploration and production activities and downstream end-user markets, and generally consists of natural gas gathering, transportation, processing, storage and fractionation activities. This industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

 

Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Offshore gathering uses a similar process, but production platforms provide production handling services, which in the case of a well producing a mixture of oil and gas involves the separation of natural gas from the oil and water before the natural gas enters the gathering lateral. Gathering laterals then connect to a main or trunk line of larger diameter pipe. The mainline then transports the natural gas collected from the various laterals to an onshore location, typically a treating facility or gas processing plant. Our Natural Gas Pipelines & Services business segment provides for the gathering, transmission, and storage of natural gas in Louisiana, and currently consists of over 1,000 miles of onshore natural gas pipelines.

 

Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications. The principal component of natural gas is methane, but most natural gas also contains varying amounts of NGLs including ethane, propane, normal butane, isobutane and natural gasoline. NGLs have economic value and are utilized as a feedstock in the petrochemical and oil refining industries or directly as a heating, engine or industrial fuel. Once separated from the natural gas, NGLs must be handled and transported to its end users through a dedicated pipeline system.

 

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Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the processed natural gas to industrial end-users and utilities and to other pipelines. Our Natural Gas Pipelines & Services business segment currently engages in natural gas transportation.

 

NGL fractionation facilities separate mixed NGL streams into discrete NGL products, including ethane, propane, normal butane, isobutane, natural gasoline and propylene, which are also called “purity NGLs.” The three primary sources of mixed NGLs fractionated in the United States are (i) domestic natural gas processing plants, (ii) domestic crude oil refineries and (iii) imports of butane and propane mixtures. NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers in order to take advantage of the different boiling points of various NGL products. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off to the top of the tower where it is condensed and routed to storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated, and a heavier NGL product is separated and stored. This process is repeated until the NGLs have been separated into all of their components. Since the fractionation process requires large quantities of heat, energy costs are a major component of the total cost of fractionation.

 

NGLs are transported to market by means of pipelines, pressurized barges, rail car and tank trucks. The method of transportation utilized depends on, among other things, the existing resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of NGLs being transported. Pipelines are generally the most cost-efficient mode of transportation when large, steady volumes of NGLs are to be delivered. Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline that provide for the transportation of propylene in Texas and Louisiana.

 

In general, refinery-grade propylene (a mixture of propane and propylene) is separated into either polymer-grade propylene or chemical-grade propylene along with by-products of propane and mixed butane. Polymer-grade propylene can also be produced from chemical-grade propylene feedstock. Chemical-grade propylene is also a by-product of olefin (ethylene) production. The demand for polymer-grade propylene is attributable to the manufacture of polypropylene, which has a variety of end uses, including packaging film, fiber for carpets and upholstery and molded plastic parts for appliance, automotive, houseware and medical products. Chemical-grade propylene is a basic petrochemical used in plastics, synthetic fibers and foams.

 

After NGLs are fractionated, the fractionated products are stored for customers when they are unable or do not wish to take immediate delivery. NGL storage customers may include both NGL producers, who sell to end users, and NGL end users, such as retail propane companies and petrochemical facilities. Both the producers and the end users seek to store NGL products to ensure an adequate supply for their respective customers over the course of the year, particularly during periods of increased demand. We maintain NGL storage facilities as part of our NGL & Petrochemical Storage Services business segment that help us meet this industry need.

 

The following sections present a detailed overview of our business segments, including information regarding our principal plants, pipelines and other assets, the principal products produced, services rendered, seasonality, competition and regulation. Our results of operations and financial condition are subject to a variety of risks. For information regarding our key risk factors, please read Item 1A of this annual report.

 

NGL & Petrochemical Storage Services Segment

 

Properties. Our NGL & Petrochemical Storage Services segment consists of three integrated and strategically located underground storage facilities in Mont Belvieu, Texas, which we refer to as Mont Belvieu East, West and North storage facilities. We have multiple pipelines that interconnect these facilities, and each facility is comprised of a network of caverns located several hundred feet below ground. These facilities include 33 storage caverns with an aggregate underground storage capacity of

 

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approximately 100 MMBbls, and a brine system with approximately 20 MMBbls of above-ground storage pit capacity and two brine production wells. The facilities are owned by Mont Belvieu Caverns.

 

These assets receive, store and deliver NGLs and petrochemical products, such as ethane and propane, for industrial customers located along the upper Texas Gulf Coast. This area has the largest concentration of petrochemical plants and refineries in the United States. The storage facilities are interconnected by multiple pipelines to other producing and offtake facilities throughout the Gulf Coast, including the largest NGL import/export facility in this region owned by Enterprise Products Partners, as well as connections to the Rocky Mountain and Midwest regions via the Seminole pipeline and to the Louisiana Gulf Coast via the Lou-Tex NGL pipeline, which are NGL pipelines owned by Enterprise Products Partners.

 

 

 

 

Mont Belvieu Caverns derives essentially all of its revenues from four main sources. These sources are:

 

 

 

 

 

We charge our customers monthly storage reservation fees to reserve a specific storage capacity in our underground caverns. The customers pay reservation fees based on the quantity of capacity reserved rather than on the amount of reserved capacity actually utilized. When a customer exceeds its reserved capacity, we charge those customers an excess storage fee. In addition, we charge our customers throughput fees based on volumes injected and withdrawn from the storage facility. Lastly, brine production revenues are derived from customers that use brine in the production of chlorine and caustic soda, which is used in the production of PVC and for industrial products used in crude oil production and fractionation. Brine is produced by injecting fresh water into a well to create cavern space within the salt dome. This process enables brine to be produced for our customers, as well as for developing new wells for product storage.

 

During 2005 and 2006, we constructed additional brine production capacity and above-ground brine storage reservoirs at Mont Belvieu. One of the projects was completed and placed in service in the first quarter of 2007, and the other project is expected to be completed in the second quarter of 2007. We retained $7.8 million from the proceeds of our initial public offering to fund our 66% share of estimated capital expenditures to complete these projects. Through December 31, 2006, we recorded total capital expenditures of $71.5 million related to these projects.

 

Customers. Our customers include a broad range of NGL and petrochemical producers and consumers, including many of the petrochemical facilities and refineries in the Texas Gulf Coast and the

 

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Louisiana Gulf Coast. Our five largest third-party customers, which accounted for 34% of our total storage revenues for the year ended December 31, 2006, were ExxonMobil, ChevronPhillips, Dow, Shell and Westlake Petrochemicals. Underground storage services we provide to Enterprise Products Partners for the storage of NGLs and petrochemicals accounted for 34% of our total storage revenues for the year ended December 31, 2006.

 

Contracts. We have a broad range of customers with contract terms that vary from month-to-month to long-term contracts with durations of one to ten years. We currently offer our customers, in various quantities and at varying terms, two main types of storage contracts: multi-product fungible storage and segregated product storage. Multi-product fungible storage allows customers to store any combination of fungible products. Segregated product storage allows customers to store non-fungible products such as propylene, ethylene and naphtha. Segregated storage allows a customer to reserve an entire storage cavern and have its own product injected and withdrawn without having its product commingled. We evaluate pricing, volume and availability for storage on a case-by-case basis.

 

Related Party Contracts. EPOLP has seven contracts for storage with Mont Belvieu Caverns that include multi-product fungible storage for its NGL marketing activities and for feedstocks for its isomerization, iso-octane, NGL fractionation, and propylene fractionation businesses and segregated product storage for polymer grade propylene that is produced at propylene fractionation facilities. These contracts last five to ten years. See Item 13 of this annual report for additional information regarding our ongoing relationship with Enterprise Products Partners.

 

For the years ended December 31, 2006, 2005 and 2004, we recorded $20.1 million, $17.6 million and $17.0 million, respectively, in storage revenues from Enterprise Products Partners.

 

Seasonality. We operate our NGL and related product storage facilities based on the needs and requirements of our customers. We usually experience an increase in the demand for storage services during the spring and summer months due to increased feedstock storage requirements for motor gasoline production and a decrease during the fall and winter months when propane inventories are being withdrawn for heating needs. In general, our import volumes peak during the spring and summer months and our export volumes are at their highest levels during the winter months. Typically, we do not experience any significant seasonality with our petrochemical customers because those customers withdraw and inject petrochemicals on a regular basis.

 

Competition. Our competitors in the NGL, petrochemical and related product storage business are integrated major oil companies, chemical companies and other storage and pipeline companies. We compete against Mont Belvieu Storage Partners, L.P., Targa Resources, Texas Brine and ONEOK in the Gulf Coast region. The principal competitive factors affecting our product storage business are storage fees, quantity and location of pipeline connections and operational dependability. We believe that the fees we charge our customers are competitive with those charged by other storage operators because we have historically been able to renew existing contracts as they mature, yielding many long-standing relationships. We are distinguished from our competitors by the location and quantity of our pipeline connections. The number of pipeline connections gives us flexibility to offer a wide variety of receipt and delivery options to customers and meet their requests on an efficient basis. Our pipeline connections to the petrochemical plants, NGL fractionators and imports from the Houston ship channel allow us to effectively compete in this business because these are the services required by our customers. In addition, we differentiate ourselves through our emphasis on operational dependability that consists of a focus on maintaining our facilities.

 

NGL and Petrochemical Sources and Transportation Options. We generally receive the NGLs and petrochemicals that we inject into our facilities, and our customers generally choose to transport the NGLs and petrochemical that we withdraw from our facilities, through the intrastate and interstate NGL and petrochemical pipelines that interconnect with our storage facilities, including Black Lake, Lakemont, Lou-Tex NGL, Skelly-Belvieu, Cypress, Seadrift, Chaparral, West Texas and Panola. In addition, we are connected to (i) some of Enterprise Products Partners’ pipelines, including the Seminole pipeline, the Port Neches Pipeline and the Channel Pipeline system (ii) the truck and rail loading and unloading facilities

 

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owned by Enterprise Products Partners (iii) numerous other pipelines through several interconnecting pipelines to ARCO Junction, a large pipeline hub in Mont Belvieu, Texas (iv) multiple third-party pipelines owned by Equistar, ExxonMobil, ONEOK, Huntsman, ChevronPhillips, Dow, Valero and Shell (v) all of the NGL fractionators in Mont Belvieu that are owned by Enterprise Products Partners, Targa, ONEOK and Gulf Coast Fractionators.

 

Mont Belvieu Expansion Opportunities. We are evaluating several projects to better integrate our three Mont Belvieu storage facilities. These projects include additional pipelines to more efficiently connect the facilities and additional entries into certain wells to increase flow rates. We are also evaluating projects that would allow us to store natural gas. The contemplated Mont Belvieu expansion project (the “Mont Belvieu Expansion”) is currently anticipated to include new entries into existing wells, the conversion of existing wells to store natural gas and the installation of new piping and certain related facilities, which may be commenced during 2007 in the estimated range of $25 to $75 million. Additional expenditures of up to $200 million may be made during 2008 and 2009. Pursuant to the Mont Belvieu Caverns limited liability company agreement, EPOLP may, in its sole discretion, fund a portion of any costs related to these projects. Additionally, we may finance any such projects through borrowings under our revolving credit facility or the issuance of debt or additional equity. For a further description of our agreements with Enterprise Products Partners relating to these potential expansion opportunities, see Item 13.

 

Import/Export Business. Enterprise Products Partners has a growing import/export business in which it imports various NGL products and transports these to and from our facilities in Mont Belvieu, Texas. These products can be stored in our underground storage facilities for our customers. Enterprise Products Partners is in the process of expanding this import/export capability and expects the projects to be completed in the second quarter of 2007.

 

Natural Gas Pipelines & Services Segment

 

Properties. Our Natural Gas Pipelines & Services segment consists of the Acadian Gas System, which is an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas System links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, located primarily in the natural gas market area of the Baton Rouge — New Orleans — Mississippi River corridor. In the aggregate, the Acadian Gas System includes over 1,000 miles of high-pressure transmission lines and lateral and gathering lines with an aggregate throughput capacity of approximately 1.0 Bcf/d and 3.0 Bcf of storage capacity.

 

The Acadian Gas System has over 150 physical end-user market direct connections. In addition, the system interconnects with 12 interstate and 4 intrastate pipelines through 50 separate interconnections, has a bi-directional interconnect with the largest U.S. natural gas marketplace at the Henry Hub, and is directly connected to six merchant and utility electric generation facilities with over 6,000 megawatts of generating capacity. The numerous interconnections allow the Acadian Gas System to leverage basis differentials across the South Louisiana pipeline network, maintain a diversified supply portfolio and create capacity and transportation opportunities for its shippers. The Acadian Gas System’s bi-directional interconnect with the Henry Hub provides physical and financial pricing flexibility, in addition to facilitating access to the many buyers and sellers of natural gas at the hub.

 

The Acadian Gas System includes the following assets:

 

 

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Henry Hub, the Acadian pipeline has the capability to deliver gas to markets that it does not physically reach. The Acadian pipeline has a throughput capacity of approximately 650 MMcf/d. The Acadian pipeline maintains multiple active interconnects with the Cypress pipeline to facilitate gas deliveries between the systems as may be required to meet customer needs.

 

 

 

 

System Throughput. Natural gas throughput on the Acadian Gas System consists of a combination of natural gas sales volumes owned by us and transportation volumes delivered on behalf of third-party shippers. Natural gas sales volumes and transportation volumes represented approximately 43% and 57%, respectively, of the average daily natural gas throughput volumes during 2006. The following table summarizes the Acadian Gas System’s natural gas sales and transportation volumes for the periods indicated (volumes in BBtus/d):

 

 

 

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Customers. The Acadian Gas System transported 759 BBtus/d of natural gas to its customers during 2006. We have long-standing relationships with a majority of our customers. Many of our customers purchase and transport a substantial portion of their natural gas requirements through the Acadian Gas System and for some customers our pipelines are the only access point for their natural gas supplies. Our customers include:

 

 

 

 

 

The Acadian Gas System has a diversified customer base, with its largest customer, ExxonMobil, representing only 10% of its total revenue in 2006 and the top ten customers representing only 40% of its total revenue in 2006.

 

Contracts and Transportation Services. In addition to its marketing gas activities, Acadian Gas provides fee-based gas transportation services for producers and gas marketing companies under intrastate and interruptible NGPA Section 311 transportation contracts. The primary term of these transportation service contracts may vary from month-to-month to longer-term contracts, with durations typically of one to three years. The revenues derived from these gas transportation contracts are based on the quantities of gas delivered multiplied by the per-unit transportation rate paid. Based on volumes moved, the most significant shippers on the Acadian Gas System include ExxonMobil, Coral Energy Resources, BP Energy and BG Energy Merchants. These shippers transport gas on the Acadian Gas System to meet the natural gas requirements of their affiliated industrial and power generation facilities, and to market commodity gas services to third parties. ExxonMobil is the most significant long-term shipper on the Acadian Gas System. We entered into a long-term gas transportation agreement with ExxonMobil in 1993 in conjunction with our acquisition of the Cypress pipeline, which was formerly owned and operated by ExxonMobil. The primary term of this agreement expired on December 1, 2006, but the parties entered into an amendment to extend the term until November 2009. During 2006, ExxonMobil shipped approximately 147 BBtus/d on the Acadian Gas System, utilizing the system as the primary fuel gas pipeline service provider for its Baton Rouge Refinery and Chemical complex.

 

Natural Gas Sales. The Acadian Gas System is currently connected to approximately 116 customers with an approximate total gas requirement of over 3.0 Bcf/d. The system has maintained active and long-term relationships, and currently has long-term natural gas sales or transportation contracts, with most of these customers. Our natural gas sales arrangements are implemented under contracts with market-based pricing indices that correspond to the pricing indices utilized in our gas purchasing activities.

 

The majority of gas sales on the Acadian Gas System are made pursuant to long-term contracts, most of which are at least one year in duration. Gas sales are also made under short-term agreements, which generally range from one day to one month. Much of our gas sales volume is under agreements that provide for minimum annual volumes to be delivered at Henry Hub indexed market prices (determined monthly), plus a predetermined adjustment or differential. The Acadian Gas System has historically received higher margins under long-term contracts that provide customers with supply certainty as well as value added services to ensure gas supplies through dedicated facilities. These additional services are necessary to accommodate large swings in a customers’ natural gas requirement, which may vary hourly, daily and monthly.

 

Acadian Gas’ most significant natural gas sales contract is a 21-year arrangement with Evangeline, which was entered into in 1991 and includes minimum annual sales volumes. Evangeline uses these natural gas volumes to meet its own supply obligation under a corresponding sales agreement with Entergy Louisiana, its only customer. Under the Entergy Louisiana gas sales contract, Evangeline is obligated to make available for sale and deliver to Entergy Louisiana certain specified minimum quantities of gas on an

 

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hourly, daily, monthly and annual basis. The gas sales contract provides for minimum annual quantities of 36.75 BBtus until the contract expires on January 1, 2013 (which is coterminous with the natural gas purchase commitment with ConocoPhillips described below). Please read “Evangeline Long-Term Debt” on page 15 for a discussion regarding the use of proceeds by Evangeline from these natural gas sales.

 

A portion of the revenues Acadian Gas receives from Evangeline in connection with this contract are attributable to a “seller’s margin” provision. The “seller’s margin” provision sets forth a fixed dollar amount per MMBtu (as defined in the contract) paid by Evangeline each month and is used to calculate fees incurred when the buyer exercises its option to reduce the minimum annual quantity of gas it purchases or when firm gas is delivered pursuant to the contract.

 

The electric utility and industrial customers of Acadian Gas normally consumes the natural gas in their own operations for fuel or feedstock, while local distribution companies and city-gate systems generally resell the natural gas to the customers of their respective gas pipeline systems.

 

Natural Gas Purchases. The Acadian Gas System currently purchases gas supply from 41 gas producers through 59 gas production receipt locations. Substantially all of the Acadian Gas System’s natural gas requirements are purchased under contracts that contain market-responsive pricing provisions. The Acadian Gas System’s most significant long-term gas purchase commitment is with ConocoPhillips, which was entered into in 1991 as part of the formation of Evangeline Gas Pipeline Company, L.P. This gas purchase contract expires on January 1, 2013 (which is coterminous with the natural gas sales agreement with Evangeline described above) and provides for minimum annual quantities of natural gas to be purchased by the Acadian Gas System, similar in structure to the minimum annual obligations between Acadian Gas System and Evangeline, and the corresponding obligations between Evangeline and Entergy Louisiana. The pricing terms of the gas purchase contract and the Entergy Louisiana gas sales contract are based on a weighted-average cost of natural gas each month (subject to certain market index price ceilings and incentive margins), plus a pre-determined margin. The amount of natural gas purchased pursuant to this contract totaled 17.9 BBtus in 2006, 17.4 BBtus in 2005 and 18.2 BBtus in 2004. The amounts paid by the Acadian Gas System for natural gas purchased under this contract totaled $134.9 million in 2006, $148.3 million in 2005 and $112.7 million in 2004.

 

Natural Gas Interconnections.  The Acadian Gas System procures gas supply from natural gas production facilities, third party natural gas pipelines, and market center pipeline hubs such as the Henry Hub and the Nautilus Hub operated by third parties. The Acadian Gas System has approximately 50 pipeline-to-pipeline interconnects with 12 interstate pipeline systems, and four unaffiliated intrastate pipeline systems. These third-party gas supplies in support of Acadian Gas System’s gas marketing activities and as receipt volumes for gas transportation activities may be sourced from any of these locations as pipeline pressures, facility interconnect capacities and landed gas pricing levels will dictate.

 

The Acadian Gas System includes a bi-directional interconnect with the Henry Hub which is generally considered to be one of the most liquid natural gas market locations in North America. The Henry Hub has interconnects with nine interstate and four intrastate pipelines providing shippers with access to pipelines reaching markets in the Midwest, Northeast, Southeast, and Gulf Coast regions of the United States. The Henry Hub is also the delivery point for the New York Mercantile Exchange (“NYMEX”) natural gas futures contract with NYMEX deliveries occurring at the Henry Hub being handled the same as cash-market transactions, thereby providing the connected Henry Hub participants with additional market flexibility.

 

The Acadian Gas System is also connected to the Nautilus Hub, which is the terminal end of the Nautilus Gas Pipeline system. The Nautilus Gas Pipeline system is a 101-mile, 30-inch gas transmission system regulated by the Federal Energy Regulatory Commission (“FERC”) that gathers deepwater Gulf of Mexico natural gas production for delivery onshore in St. Mary Parish, Louisiana at the Neptune natural gas processing plant, which is operated by Enterprise Products Partners. After natural gas is processed at the Neptune facility, it is redelivered into the Nautilus Hub which has seven separate interconnects with interstate and intrastate gas pipeline systems, including the Acadian Gas System.

 

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Evangeline Long-Term Debt. In connection with the acquisition of the Entergy Louisiana natural gas sales contract and construction of the Evangeline pipeline, Evangeline entered into a long-term debt arrangement. At December 31, 2006, this long-term debt consisted of: (i) $18.2 million in principal amount of 9.9% fixed interest rate senior secured notes due December 2010 (the “Series B” notes); and (ii) a $7.5 million subordinated note payable to The Louisiana Land and Exploration Company (“LL&E,” formerly known as Evangeline Northwest Corporation). The Series B notes are collateralized by: (i) Evangeline’s property, plant and equipment; (ii) proceeds from the Entergy Louisiana natural gas sales contract; and (iii) a debt service reserve requirement. Scheduled principal repayments on the Series B notes are $5 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. Evangeline incurred the LL&E Note obligations in connection with its acquisition of the Entergy Louisiana natural gas sales contract in 1991. The LL&E Note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. Substantially all of the net proceeds received by Evangeline from its contracts with Entergy Louisiana are used to pay off the Series B notes and LL&E Note.

 

Entergy Louisiana’s Option. Entergy Louisiana has the option to purchase the Evangeline pipeline for a nominal price, plus the complete performance and compliance with the gas sales contract. The option period begins on the earlier of July 1, 2010 or upon the payment in full of the Series B Notes and the LL&E Note, and terminates on December 31, 2012. We cannot know when, or if, Entergy Louisiana will exercise this option. Factors that may influence Entergy Louisiana’s decision include, but are not limited to, Entergy Louisiana’s future business plans, natural gas procurement strategies, required regulatory approvals, and the pipeline system’s residual value, if any, at the time the option is exercisable.

 

Commodity Price Risk. With regard to physical gas marketing activities, the Acadian Gas System purchases gas in quantities and under pricing terms that mirror its sales obligations. Within the transportation services function, the Acadian Gas System transports quantities of gas on behalf of others, with those shippers being responsible for managing any commodity price risk that may be associated with matching gas purchases with gas sales. The Acadian Gas System does not engage in any type of commodity hedging, nor any futures, options, or basis trading for the purpose of attempting to create or optimize a proprietary trading position. Certain physical customers of the Acadian Gas System will from time to time request the ability to control the volatility inherent in a monthly indexed natural gas sales arrangement, which requires that the Acadian Gas System take a position in the futures market corresponding to the hedge request of that customer. When this transaction takes place, it is only at the request of the customer, and only in a volume and for a period of time that corresponds to coverage of that customer’s request, and as it would relate to that customer’s physical delivery contract with the Acadian Gas System. In addition, Acadian Gas utilizes swaps to convert the price terms of its natural gas purchases to match the terms of its current month natural gas sales. Based on seasonal requirements, Acadian Gas also buys gas off the NYMEX Exchange for physical delivery due to the NYMEX’s delivery terms.

 

Seasonality. Typically, the Acadian Gas System experiences higher throughput rates during the summer months as gas-fired power generation facilities increase output to satisfy residential and commercial demand for electricity for air conditioning. Likewise, seasonality impacts the timing of injections and withdrawals at our natural gas storage facility. In the winter months, natural gas is needed as fuel for residential and commercial heating, generally increasing the need for deliveries to local distribution companies and city-gate stations.

 

Competition. Our Acadian Gas System competes with several onshore natural gas pipelines in the South Louisiana market on the basis of price (in terms of transportation fees or natural gas selling prices), location, service, reliability and flexibility. The transportation fees and natural gas sales prices we charge our customers are competitive with those charged by other onshore pipelines in the area because we rely on certain published indices for our pricing. We are distinguished from our competitors within the onshore South Louisiana market because of our long-standing customer relationships. Due to the limited number of alternative delivery pipeline connections to those customers, we have been able to retain our customers for many years. Our competitors have the ability to connect into various customers on our pipeline but at a higher cost due to new pipelines and other related facilities. It is critical to the customers in the region that

 

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we provide reliable service to enable our customers’ flexibility of supply through the many connections to our system. Because of our location and long-standing presence in South Louisiana, we are able to compete effectively in this market.

 

Petrochemical Pipeline Services Segment

 

Properties. Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline that provide for the transportation of propylene in Texas and Louisiana. This segment includes the following assets:

 

 

 

Customers.  Shell and ExxonMobil are the only customers that currently transport chemical-grade propylene through our Lou-Tex Propylene Pipeline. Shell is the only customer that currently transports polymer-grade propylene through our Sabine Propylene Pipeline.

 

Contracts.  Enterprise Products Partners entered into separate product exchange agreements with Shell and ExxonMobil involving the use of our Sabine Propylene and Lou-Tex Propylene Pipelines. Concurrently with the closing of our initial public offering, Enterprise Products Partners assigned these exchange agreements to us. As a result of these exchange agreements, we agree to receive propylene in one location and deliver propylene at another location.

 

 

 

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Related Party Contracts. Enterprise Products Partners assigned its exchange agreements for the use of the Lou-Tex Propylene and Sabine Propylene Pipelines with Shell and ExxonMobil to us concurrently with the closing of our initial public offering. Prior to 2004, the Sabine Propylene Pipeline was regulated by the FERC. The Lou-Tex Propylene Pipeline was also subject to the FERC’s jurisdiction until 2005. For the periods in which the Sabine Propylene Pipeline and the Lou-Tex Propylene Pipeline were subject to FERC regulations, related party revenues with Enterprise Products Partners were based on the maximum tariff rate allowed for each system. We continued to charge Enterprise Products Partners such maximum transportation rates after both entities were declared exempt from FERC oversight. The assignment of these exchange agreements to us concurrently with the closing of our initial public offering made the tariffs charged by us equal to the fees charged to ExxonMobil and Shell per the terms of these agreements.

 

Throughput. The following table summarizes throughput of each of our petrochemical pipelines for the periods indicated (volumes in Bbls/d):

 

 

Seasonality. Our propylene transportation business has historically exhibited little seasonality.

 

Competition. Our petrochemical pipelines encounter competition from fully integrated oil companies and various petrochemical companies in the Gulf Coast market. Our petrochemical transportation competitors have varying levels of financial and personnel resources, and competition generally revolves around price, service, logistics and location. We differentiate ourselves from the larger oil and petrochemical companies primarily through the location of our pipelines and dedication of our pipelines to a single product service. Our petrochemical pipelines are in single product service due to the required purity of the product being shipped. Because there are no other pipelines in our market area which ship the same single product, we are able to compete against our larger competitors for this service. In the future, a competitor could change service of an existing pipeline to ship single products, but they would have to incur additional costs to connect to our customers.

 

NGL Pipeline Services Segment

 

Properties. Our NGL Pipeline Services segment includes our DEP South Texas NGL Pipeline System, a 286-mile intrastate pipeline system and related interconnections used to transport NGLs from two fractionation facilities located in South Texas to Mont Belvieu, Texas. The DEP South Texas NGL Pipeline System became operational and began transporting NGLs in January 2007 after undergoing modifications, extensions and interconnections, which we refer to as Phase I. Enterprise Products Partners purchased a 220-mile segment of pipeline, ranging from 12 inches to 16 inches in diameter, from a third party in August 2006 that was the initial component of this system. This segment of the DEP South Texas NGL Pipeline System originates in Corpus Christi, Texas and extends to Pasadena, Texas and has a current capacity of approximately 100,000 Bbls/d, which is expandable to 175,000 Bbls/d. During Phase I:

 

 

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During January 2007, an affiliate of Enterprise Products Partners acquired an additional 10-mile, 18-inch segment of pipeline from an affiliate of TEPPCO, which connects the leased TEPPCO pipeline to Mont Belvieu, Texas. This 10-mile pipeline segment was purchased from TEPPCO for an aggregate purchase price of $8.0 million. This pipeline segment was included with the operations and assets contributed to us by Enterprise Products Partners at the closing of our initial public offering.

 

During Phase II, we will construct 22 miles of 18-inch pipeline to replace the leased 11-mile, 10-inch pipeline and the segments of 12-inch pipeline acquired from a third party. The Phase II upgrade will provide a significant increase in pipeline capacity and is expected to be operational during the third quarter of 2007.

 

Customer and Related Party Contract. The sole customer of our NGL Pipeline Services segment is Enterprise Products Partners, which uses the DEP South Texas NGL Pipeline System to ship NGLs processed at the Shoup fractionation plant in Corpus Christi, Texas, the Armstrong fractionation plant located near Victoria, Texas and NGLs purchased from third parties in South Texas to Mont Belvieu, Texas. We have entered into a ten-year transportation contract with Enterprise Products Partners that includes all of the volumes of NGLs transported on the DEP South Texas NGL Pipeline System. Under this contract, Enterprise Products Partners pays us a dedication fee of no less than $0.02 per gallon for all NGLs produced at the Shoup and Armstrong fractionation plants whether or not Enterprise Products Partners ships any NGLs on the pipeline system. We do not take title to the products transported on the DEP South Texas NGL Pipeline System; rather, Enterprise Products Partners retains title and the associated commodity risk.

 

Revenues. Revenues from a dedication fee of no less than $0.02 per gallon of NGLs produced at Enterprise Products Partners’ Shoup and Armstrong fractionation plants represent substantially all of the revenues of our NGL Pipeline Services segment. These NGL production volumes have varied during recent periods and may vary in the future. Because the DEP South Texas NGL Pipeline System provides transportation services to Enterprise Products Partners on a dedicated fee basis, the results of our operations are dependent upon the level of production of NGLs from the Shoup and Armstrong fractionation plants. If one of the plants shuts down or otherwise reduces production, our revenues would decrease.

 

Seasonality. Our NGL Pipeline Services segment does not exhibit a significant degree of seasonality.

 

Supplies. The sources of the NGLs transported on our DEP South Texas NGL Pipeline System originate primarily from the Shoup fractionation plant located in Corpus Christi, Texas and the Armstrong fractionation plant located 26 miles north of Victoria, Texas.

 

 

 

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The Shoup and Armstrong fractionation plants produced the following aggregate amounts of NGLs during the periods set forth below:

 

 

Natural Gas Supply. Natural gas supplies processed by the Shoup and Armstrong facilities are sourced from Texas Gulf Coast producing areas. Production trends based on 2005 EIA data show a 1% per year increase over the last 25 years. New drilling permits (per IHS Inc.) and rig counts (per Baker Hughes) have also increased 5% per year over the last three years. The EIA report on production of rich natural gas also shows an annual average increase of 1% over the last 25 years. New sources of rich gas may exist in the Cretaceous sands of southwest Texas and the Oligocene Vicksburg formations below 14,000 feet in south Texas. In the mid-Gulf Coast region, rich Wilcox gas is found at depths in the 10,000 feet to 15,000 feet range. Shale gas in these areas may also have high liquids content.

 

Title to Properties

 

Our real property holdings fall into two basic categories: (1) parcels that we own in fee, such as the land and underlying storage caverns at Mont Belvieu, Texas and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. The fee sites upon which our major facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way or license held by us or to our title to any material lease, easement, right-of-way, permit or license. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way and licenses.

 

Capital Spending

 

We are committed to the long-term growth and viability of Duncan Energy Partners. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures with industry partners. We believe that we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected future production increases from the deepwater Gulf of Mexico. See Item 7 “Capital Spending” and Note 12 of Duncan Energy Partners Predecessor for more information.

 

Regulation

 

Regulation of Our Intrastate Natural Gas Pipelines and Services

 

At the federal level, our gas pipelines and gas storage facilities are subject to regulations of the FERC under the Natural Gas Policy Act of 1978 (“NGPA”). Our natural gas intrastate systems provide transportation and storage pursuant to Section 311 of the NGPA and Section 284 of the FERC’s regulations. Under Section 311 of the NGPA, an intrastate pipeline company may transport gas for an interstate pipeline company or any local distribution company served by an interstate pipeline. We are required to provide these services on an open and nondiscriminatory basis and to make certain rate and other filings and reports in compliance with the regulations. The rates for Section 311 service can be established by the FERC or the respective state agency. The associated rates may not exceed a fair and equitable rate and are subject to challenge.

 

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In the past, the FERC has approved market-based rates for Section 311 storage service for the storage facility in Louisiana. Recently, we filed petitions for each of our Acadian and Cypress pipelines requesting approval of increased rates for interruptible transportation service performed under Section 311, to be effective October 1, 2006, subject to refund. Each of these petitions was protested by a single shipper. We did not place the proposed rates for the Acadian and Cypress pipelines into effect on October 1, 2006. Therefore, there are no currently effective rates that are subject to refund, although the currently effective rates remain subject to complaint by all shippers. We are currently engaged in settlement discussions with the shipper and the FERC staff to establish the proposed rates for the Acadian and Cypress pipelines. Any settlement agreement between the parties must be approved by the FERC. The Louisiana Public Service Commission also reviews and approves rates for pipelines providing Section 311 service in Louisiana. For example, the Louisiana Public Service Commission regulates Acadian Gas’ city gate sales. We also have a natural gas underground storage facility in Louisiana that is subject to state regulation. In addition to the above-regulations, the natural gas industry has historically been subject to numerous other forms of federal, state and local regulation.

 

Regulation of Our Petrochemical Pipeline Services

 

Our interstate Lou-Tex Propylene and Sabine Propylene Pipelines are common carrier pipelines regulated by the Surface Transportation Board (“STB”) under the current version of the Interstate Commerce Act (“ICA”). The ICA and its implementing regulations give the STB authority to regulate the rates we charge for service on the propylene pipelines and generally require that our rates and practices be just and reasonable and nondiscriminatory.

 

The majority of the natural gas pipelines in the Acadian Gas System are intrastate common carrier pipelines that are subject to various Louisiana state laws and regulations that affect the rates it charges and the terms of service. We also have a natural gas underground storage facility in Louisiana that is subject to state regulations.

 

For additional information regarding the potential impact of federal, state or local regulatory measures on our business, please read Item 1A “Risk Factors.”

 

Environmental and Safety Matters

 

General

 

Our operations are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations. These include, without limitation: the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the Clean Water Act; the Oil Pollution Act; and analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs at a facility that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. Any or all of this could materially affect our financial position, results of operations and cash flows.

 

We believe our operations are in material compliance with applicable environmental and safety laws and regulations, and that compliance with existing environmental and safety laws and regulations are not expected to have a material adverse effect on our financial position, results of operations or cash flows. Environmental and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the

 

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environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. As of December 31, 2006, we had a reserve of approximately $0.4 million included in other current liabilities for remediation of ground contamination related to the Acadian Gas System. Below is a discussion of the material environmental laws and regulations that relate to our business.

 

Water

 

The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States, as well as state waters. Permits must be obtained to discharge pollutants into these waters. The Clean Water Act imposes substantial potential liability for the removal and remediation of pollutants.

 

The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution -- prevention, containment and cleanup, and liability. OPA subjects owners of certain facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. Any unpermitted release of petroleum or other pollutants from our operations could also result in fines or penalties. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety (“OPS”) or the EPA, as appropriate.

 

Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Contamination resulting from spills or releases of petroleum products is an inherent risk within our industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operation, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, but such costs are site specific and we cannot assure you that the effect will not be material in the aggregate.

 

Air Emissions  

 

Our operations are subject to the Federal Clean Air Act (the “Clean Air Act”) and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.

 

Our permits and related compliance obligations under the Clean Air Act, as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas, may require our operations to incur capital expenditures to add to or modify existing air emission control equipment and strategies. In addition, some of our facilities are included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the Clean Air Act and many state laws. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however,

 

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that such requirements will not have a material adverse effect on our operations, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

 

Congress is currently considering proposed legislation directed at reducing “greenhouse gas emissions.” It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact our business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial position, results of operations and cash flows.

 

Solid Waste  

 

In our normal operations, we generate hazardous and non-hazardous solid wastes, including hazardous substances that are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws, which impose detailed requirements for the handling, storage treatment and disposal of hazardous and solid waste. We also utilize waste minimization and recycling processes to reduce the volumes of our waste. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the waste meets certain treatment standards or the land-disposal method meets certain waste containment criteria.

 

Environmental Remediation

 

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund” laws, impose liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred, transporters that select the site of disposal of hazardous substances and companies that disposed of or arranged for the disposal of any hazardous substances found at a facility. Under CERCLA, these persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our operations, our pipeline systems generate wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by us requires clean up in the future, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.

 

Pipeline Safety Matters

 

We are subject to regulation by the United States Department of Transportation (“DOT”) under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. The HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the Secretary of Transportation. We believe we are in material compliance with these HLPSA regulations.

 

We are subject to the DOT regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks. We believe we are in material compliance with these DOT regulations.

 

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We are also subject to the DOT Integrity Management regulations, which specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCAs”). HCAs are defined to include populated areas, unusually sensitive environmental areas and commercially navigable waterways. The regulation requires the development and implementation of an Integrity Management Program (“IMP”) that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. The regulation also requires periodic review of HCA pipeline segments to ensure adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised by the assessment and analysis. In compliance with these DOT regulations, we identified our HCA pipeline segments and have developed an IMP. We believe the established IMP meets the requirements of these DOT regulations.

 

Risk Management Plans  

 

We are subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain facilities. These regulations are intended to work with the Occupational Safety and Health Act (“OSHA”) Process Safety Management regulations (see “Safety Matters” below) to minimize the offsite consequences of catastrophic releases. The regulations required us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program. Generally, we believe we are operating in compliance with our risk management program.

 

Safety Matters

 

Certain of our facilities are also subject to the requirements of the federal OSHA and comparable state statutes. We believe we are in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.

 

We are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process involving a chemical at or above the specified thresholds or any process involving certain flammable liquid or gas. We believe we are in material compliance with the OSHA PSM regulations.

 

The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request.

 

Employees

 

We do not have any employees. EPCO employs most of the persons necessary for the operation of our business. At December 31, 2006, EPCO had approximately 80 dedicated employees and 176 employees that share a portion of their time in the management and operations of our business, none of whom were members of a union. We will continue to reimburse EPCO for the costs of all employees providing services to us. In addition to EPCO employees, we will engage various contract maintenance and other personnel who will support our operations. For additional information regarding our relationship with EPCO, see Item 13 of this annual report.

 

 

 

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Item 1A. Risk Factors.

 

An investment in our common units involves certain risks. If any of these risks were to occur, our business, results of operations, cash flows and financial condition could be materially adversely affected. In that case, the trading price of our common units could decline, and you could lose part or all of your investment.

 

The following section lists some, but not all, of the key risk factors that may have a direct impact on our business, results of operations, cash flows and financial condition. The items are not listed in terms of importance or level of risk.

 

Risks Inherent in Our Business

 

Changes in demand for and production of hydrocarbon products may materially adversely affect our results of operations, cash flows and financial condition.

 

We operate predominantly in the midstream energy sector that includes transporting and storing natural gas, NGLs and propylene. As such, our results of operations, cash flows and financial condition may be materially adversely affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. Changes in prices and changes in the relative price levels may impact demand for hydrocarbon products, which in turn may impact production and volumes transported by us and related transportation and storage handling fees. We may also incur price risk to the extent counterparties do not perform in connection with our marketing of natural gas, NGLs and propylene.

 

In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the prompt month contract in 2004 ranged from a high of $8.75 per MMBtu to a low of $4.57 per MMBtu. In 2005, the same index ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu. In 2006, the same index ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu.

 

Generally, the prices of natural gas, NGLs and other hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include:

 

 

 

 

 

 

 

 

 

 

 

 

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A decrease in demand for natural gas, NGLs, NGL products or petrochemical products by the petrochemical, refining or heating industries could materially adversely affect our results of operations, cash flows and financial position.

 

A decrease in demand for natural gas, NGLs, NGL products or petrochemical products by the petrochemical, refining or heating industries, whether because of a general downturn in economic conditions, reduced demand by consumers for the end products made with products we transport, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, increased government regulations affecting prices and production levels of natural gas or other reasons, could materially adversely affect our results of operations, cash flows and financial position. For example:

 

 

 

Any decrease in supplies of natural gas could adversely affect our business and operating results. Because of the natural decline in gas production from existing wells, our success depends on our ability to obtain access to new sources of natural gas, which is dependent on factors beyond our control.

 

Over the past two years that have been reported, gas production from state waters of the Gulf Coast region, which supplies much of our throughput, has declined an average of approximately 2.9% from 133 Bcf for 2003 to 129 Bcf for 2004, according to EIA. We cannot give any assurance regarding the gas production industry’s ability to find new sources of domestic supply. Production from existing wells and gas supply basins connected to our pipelines will naturally decline over time, which means our cash flows associated with the gathering or transportation of gas from these wells and basins will also decline over time. The amount of natural gas reserves underlying these wells may also be less than we anticipate, and the rate at which production from these reserves declines may be greater than we anticipate. Accordingly, to maintain or increase throughput levels on our pipelines, we must continually obtain access to new supplies of natural gas. The primary factors affecting our ability to obtain new sources of natural gas to our pipelines include:

 

 

 

 

 

 

The level of drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is the price of oil and natural gas. These commodity prices reached record levels during 2006, but current prices have declined in recent months. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our pipelines, which would lead to reduced throughput levels on our pipelines. Other

 

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factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits, the availability and cost of drilling rigs and other drilling equipment, and regulatory changes. Because of these factors, even if new natural gas reserves were discovered in areas served by our pipelines, producers may choose not to develop those reserves or may connect them to different pipelines.

 

Imported LNG is expected to be a significant component of future natural gas supply to the United States. Much of this increase in LNG supplies is expected to be imported through new LNG facilities to be developed over the next decade. Eleven LNG projects have been approved by the FERC to be constructed in the Gulf Coast region and an additional four LNG projects have been proposed for the region. We cannot predict which, if any, of these projects will be constructed. If a significant number of these new projects fail to be developed with their announced capacity, or there are significant delays in such development, or if they are built in locations where they are not connected to our systems, or they do not influence sources of supply on our systems, we may not realize expected increases in future natural gas supply available for transportation through our systems.

 

If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing supply basins, or if the expected increase in natural gas supply through imported LNG is not realized, throughput on our pipelines would decline which could have a material adverse effect on our financial condition, results of operations and ability to make distributions to our unitholders.

 

In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves dedicated to our pipeline systems, including our DEP South Texas NGL Pipeline System. Accordingly, volumes of natural gas gathered on our pipeline systems in the future could be less than we anticipate, which could adversely affect our cash flow and our ability to make cash distributions to unitholders.

 

In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves connected to our pipeline systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems (or to processing facilities such as those serving Enterprise Products Partners in South Texas) or the anticipated lives of such reserves. If the total reserves or estimated lives of the reserves connected to our pipeline systems, particularly in South Texas, is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our DEP South Texas NGL Pipeline System and other pipeline systems in the future could be less than we anticipate. A decline in the volumes of natural gas gathered on our pipeline systems could have an adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

 

We face competition from third parties in our midstream energy businesses.

Even if reserves exist in the areas accessed by our facilities and are ultimately produced, we may not be chosen by the producers in these areas to gather, transport, market, store or otherwise handle the hydrocarbons that are produced. We compete with others, including producers of oil and natural gas, for any such production on the basis of many factors, including but not limited to:

 

 

 

 

 

 

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Our debt level may limit our flexibility to obtain additional financing and pursue other business opportunities.

 

At the closing of our initial public offering, we had approximately $200 million of indebtedness outstanding under our credit agreement and the ability to borrow up to an additional $100 million, subject to certain conditions and limitations, under the credit agreement. Our significant level of indebtedness could have important consequences to us, including:

 

 

 

 

 

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisition, investments or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

 

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

 

Our strategy contemplates growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversifying our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating and/or pursuing, potential joint ventures, stand alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in the energy infrastructure business and increase our market position.

 

We will require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.

 

In addition, we are experiencing increased competition for the types of assets and businesses we have historically purchased or acquired. Increased competition for a limited pool of assets could result in our losing to other bidders more often or acquiring assets at less attractive prices. Either occurrence would

 

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limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher distributions in the future.

 

Our revolving credit facility contains operating and financial restrictions, including covenants and restrictions that may be affected by events beyond our control, that may limit our business and financing activities.

 

The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our credit agreement may restrict or limit our ability to:

 

 

 

 

 

 

 

Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

 

Restrictions in our revolving credit facility could limit our ability to make distributions upon the occurrence of certain events.

 

Our payment of principal and interest on our debt will reduce cash available for distributions on our common units. Our credit agreement could limit our ability to make distributions upon the occurrence of the following events, among others:

 

 

 

 

 

 

 

 

 

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Any subsequent refinancing of our current debt or any new debt could have similar or more restrictive provisions. For more information regarding our credit agreement, see Item 7.

 

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.

 

We have significant exposure to increases in interest rates. After our initial public offering and the borrowing of approximately $200 million under our credit agreement, we have approximately $200 million of consolidated debt, at variable interest rates. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

 

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

 

Our growth strategy may adversely affect our results of operations if we do not successfully integrate the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

Our growth strategy includes making accretive acquisitions. As a result, from time to time, we will evaluate and acquire assets and businesses that we believe complement our existing operations. We may be unable to integrate successfully businesses we acquire in the future. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could negatively impact our results of operations, cash flows and financial condition. Moreover, acquisitions and business expansions involve numerous risks, including but not limited to:

 

 

 

 

 

 

If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, depletion and amortization expenses. As a result, our capitalization and results of operations may change significantly following an acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our results of operations, cash flows and financial condition. In addition, any anticipated benefits of material acquisition, such as expected cost savings, may not be fully realized, if at all.

 

 

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We may not be able to make acquisitions or to make acquisitions on economically acceptable terms, which may limit our ability to grow.

 

We are limited in our ability to make acquisitions by our business opportunity agreements with Enterprise Products Partners and Enterprise GP Holdings. These agreements entitle them to take business opportunities for the benefit of themselves before allowing us to take them. In addition, our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to maintain and increase over time distributions will be limited.

 

Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.

 

Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless reduce our cash from operations on a per unit basis. Any acquisition involves potential risks, including, among other things:

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

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We depend in large part on Enterprise Products Partners and the continued success of its business as we operate our assets as part of their value chain, and adverse changes in its related businesses may reduce our revenue, earnings or cash available for distribution.

 

We have entered into a number of material contracts with Enterprise Products Partners and its subsidiaries relating to transportation, storage and leases, and our cash flows and financial condition depend in large part on the continued success of Enterprise Products Partners as we operate our assets as part of its value chain. For example, our DEP South Texas NGL Pipeline System revenues depend solely on the volumes processed at the South Texas facilities owned by Enterprise Products Partners. Enterprise Products Partners has no obligation to produce any volumes at these facilities. If anticipated volumes are not processed by Enterprise Products Partners at these facilities, our estimated revenues on this system will be reduced.

 

Any adverse changes in the business of Enterprise Products Partners, due to market conditions, sales of assets or otherwise, or the failure of Enterprise Products Partners to renew any of its material agreements with us, could reduce our revenue, earnings or cash available for distribution. See Item 13 for additional information regarding certain agreements with Enterprise Products Partners.

 

The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

 

The credit and business risk profiles of a general partner or owners of a general partner may be factors in credit evaluations of a limited partnership. This is because the general partner controls the business activities of the partnership, including its cash distribution policy and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.

 

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of the owners of our general partner, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider these entities’ leverage because of their ownership interest in and control of us, the strong operational links between them and their affiliates and us, and our reliance on Enterprise Products Partners for a substantial percentage of our revenue. Any such adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise money in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.

 

Affiliates of Enterprise Products Partners, the indirect owner of our general partner, have significant indebtedness outstanding and are dependent principally on the cash distributions from their general partner and limited partner interests in Enterprise Products Partners, Enterprise GP Holdings and TEPPCO to service such indebtedness. Any distributions by Enterprise Products Partners, Enterprise GP Holdings and TEPPCO to such entities will be made only after satisfying their then-current obligations to their creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us and our general partner from the entities that control our general partner, and other entities controlled by Dan L. Duncan, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of Dan L. Duncan or the entities that control our general partner were viewed as substantially lower or more risky than ours.

 

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow and, accordingly, affect the market price of our common units.

 

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Pipelines may suffer inadvertent damage from construction, and farm and utility equipment.

 

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Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms and floods. The location of our assets and our customers’ assets in the Gulf Coast region makes them particularly vulnerable to hurricane risk.

 

If one or more facilities that we own or that deliver natural gas or other products to us are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units.

 

EPCO maintains insurance coverage on behalf of us, although insurance will not cover many types of interruptions that might occur and will not cover amounts up to applicable deductibles. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. For example, changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. As a result, EPCO may not be able to renew existing insurance policies on behalf of us or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

 

Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

 

One of the connections between our DEP South Texas NGL Pipeline System and the Mont Belvieu facility is a pipeline we have leased from TEPPCO. The initial term of this lease will expire on September 15, 2007, and if we are unable to construct our planned replacement pipeline or extend the lease, the operations of our DEP South Texas NGL Pipeline System will be interrupted. We cannot assure that any construction will not be delayed due to government permits, weather conditions or other factors beyond our control.

 

In addition, one of the ways we intend to grow our business is through the construction of new midstream energy assets. The construction of new assets involves numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following:

 

 

 

 

 

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A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects.

 

Federal, state or local regulatory measures could materially affect our business, results of operations, cash flows and financial condition.

 

The STB regulates transportation on interstate propylene pipelines. The current version of the ICA and its implementing regulations give the STB authority to regulate the rates we charge for service on the propylene pipelines and generally requires that our rates and practices be just and reasonable and nondiscriminatory. The rates we charge for movements on our propylene pipelines may be subject to challenge and any successful challenge to those rates could adversely affect our revenues. Our interstate propylene pipelines formerly were regulated by the FERC, and we cannot guarantee that the FERC will not reassert jurisdiction over those facilities in the future.

 

The intrastate natural gas pipeline transportation services we provide are subject to various Louisiana state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge. In addition, the transportation and storage services furnished by our intrastate natural gas facilities on behalf of interstate natural gas pipelines or certain local distribution companies are regulated by the FERC pursuant to Section 311 of the NGPA. Pursuant to the NGPA, we are required to offer those services on an open and nondiscriminatory basis at a fair and equitable rate. Such FERC-regulated NGPA Section 311 rates also may be subject to challenge and successful challenges may adversely affect our revenues.

 

Although our natural gas gathering systems are generally exempt from FERC regulation under the Natural Gas Act of 1938, FERC regulation still significantly affects our natural gas gathering business. In recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue this approach, it could have an adverse effect on the rates we are able to charge in the future. In addition, the distinction between FERC-regulated transmission service and federally unregulated gathering services is the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

 

For a general overview of federal, state and local regulation applicable to our assets, see Item 1.

 

Our partnership status may be a disadvantage to us in calculating our cost of service for rate-making purposes.

 

In May 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In August 2005, the FERC also dismissed requests for rehearing of its new policy statement. On December 16, 2005, the FERC issued its first significant

 

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case-specific review of the income tax allowance issue in another company’s rate case. The FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16 order have been appealed to the United States Court of Appeals for the District of Columbia Circuit. As a result, the ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. Depending upon how the policy statement on income tax allowances is applied in practice to pipelines organized as pass-through entities, and whether it is ultimately upheld or modified on judicial review, these decisions might adversely affect us.

 

Environmental costs and liabilities and changing environmental regulation could materially affect our results of operations, cash flows and financial condition.

 

Our operations are subject to extensive federal, state and local regulatory requirements relating to environmental affairs, health and safety, waste management and chemical and petroleum products. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Certain environmental laws, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to cleanup and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

 

We will make expenditures in connection with environmental matters as part of normal capital expenditure programs. However, future environmental law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations, including the handling, manufacture, use, emission or disposal of substances and wastes.

 

Our pipeline integrity program may impose significant costs and liabilities on us.

 

The U.S. Department of Transportation issued final rules (effective March 2001 with respect to hazardous liquid pipelines and February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rules refer to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. At this time, we cannot predict the ultimate costs of compliance with this rule because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing that is required by the rule. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

 

We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could adversely affect our ability to make distributions to our unitholders.

 

The workplaces associated with our pipelines are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities and local residents. The failure to comply with OSHA requirements or general industry standards, keep adequate records or monitor occupational exposure to regulated substances could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

 

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We depend on Enterprise Products Partners and certain other key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions to our unitholders.

 

We rely on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2006 and 2005, Enterprise Products Partners and its affiliates accounted for approximately 13% and 9% of our total combined revenues, respectively. Enterprise Products Partners and its affiliates will continue to account for a significant percentage of our total revenues after our initial public offering. In addition, several of our assets also rely on only one or two customers for the asset’s cash flow. For example, the only shipper on our DEP South Texas NGL Pipeline System is Enterprise Products Partners; the only customers on our Lou-Tex Propylene Pipeline are ExxonMobil and Shell; the only customer on our Sabine Propylene Pipeline is Shell; and the only shipper on the pipeline held by Evangeline is Entergy. In order for new customers to use these pipelines, we or the new shippers would be required to construct interim pipeline connections.

 

We may be unable to negotiate extensions or replacements of these contracts and those with other key customers on favorable terms. The loss of all or even a portion of the contracted volumes of these customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions to our unitholders, unless we are able to contract for comparable volumes from other customers at favorable rates.

 

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.

 

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. We generally do not require collateral for our accounts receivable. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment or nonperformance by them could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

We depend on the leadership and involvement of Dan L. Duncan and other key personnel for the success of our and our subsidiaries’ businesses.

 

We depend on the leadership, involvement and services of Dan L. Duncan, the founder of EPCO and the Chairman of our general partner. Mr. Duncan has been integral to the success of Enterprise Products Partners and the success of EPCO, and will be integral to our success, due in part to his ability to identify and develop business opportunities, make strategic decisions and attract and retain key personnel. The loss of his leadership and involvement or the services of any members of our senior management team could have a material adverse effect on our business, results of operations, cash flows and financial condition.

 

Successful development of LNG import terminals outside our areas of operations could reduce the demand for our services.

 

Development of new, or expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas from supply basins connected to our pipelines. This could reduce the amount of gas transported by our pipelines for delivery off-system to other intrastate or interstate pipelines serving these customers. If we are not able to replace these volumes with volumes to other markets or other regions, throughput on our pipelines would decline which could have a material adverse effect on our financial condition, results of operations and ability to make distributions to our unitholders.

 

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We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

 

We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, or increased costs to renew such rights, could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to our unitholders.

 

Mergers among our customers or competitors could result in lower volumes being shipped on our pipelines, thereby reducing the amount of cash we generate.

 

Mergers among our existing customers or competitors could provide strong economic incentives for the combined entities to utilize systems other than ours and we could experience difficulty in replacing lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes would result in not only a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to our unitholders.

 

Because of our lack of asset and geographic diversification, adverse developments in our pipeline operations would reduce our ability to make distributions to our unitholders.

 

We rely on the revenues generated from our pipelines and related assets. Furthermore, our assets are concentrated in Texas and Louisiana. Due to our lack of diversification in asset type and location, an adverse development in our business or our operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

Terrorist attacks aimed at our facilities or our customers’ facilities could adversely affect our business, results of operations, cash flows and financial condition.

 

Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on our facilities or pipelines or those of our customers could have a material adverse effect on our business.

 

Risks Inherent in an Investment in Us

 

Enterprise Products Partners, EPCO and their affiliates may compete with us, and business opportunities may be directed by contract to those affiliates prior to us under the administrative services agreement.

 

Our partnership agreement does not prohibit Enterprise Products Partners, EPCO and their affiliates, other than our general partner, from owning and operating natural gas and NGL pipelines and storage assets or engaging in businesses that otherwise compete directly or indirectly with us. In addition, Enterprise Products Partners and EPCO may acquire, construct or dispose of additional midstream energy or other natural gas assets in the future, without any obligation to offer us the opportunity to purchase or construct any of these assets.

 

Under the amended and restated administrative services agreement we entered into at the closing of our initial public offering, if any business opportunity, other than a business opportunity to acquire general partner interests and other related equity securities in a publicly traded partnership, is presented to EPCO and its affiliates, us and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, then Enterprise Products Partners will have the first right to

 

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pursue such opportunity for itself or, in its sole discretion, to affirmatively direct the opportunity to us. If Enterprise Products Partners abandons the business opportunity for itself or for us, then Enterprise GP Holdings will have the second right to pursue such opportunity. If any business opportunity to acquire general partner interests and other related equity securities in a publicly traded partnership is presented, then Enterprise GP Holdings will have the right to pursue such opportunity before Enterprise Products Partners is given the opportunity to pursue it for itself or to direct it to us. Accordingly, we are limited by contract in our ability to take certain business opportunities for our partnership. See Item 13 of this annual report.

 

Our general partner and its affiliates own a controlling interest in us and have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

 

Following our initial public offering, EPOLP owns indirectly a 2% general partner interest and directly approximately 26.4% of our outstanding common units and owns and controls our general partner, which controls us. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage it and our general partner in a manner beneficial to Enterprise Products Partners and its affiliates. Furthermore, certain directors and officers of our general partner may be directors or officers of affiliates of our general partner. Conflicts of interest may arise between Enterprise Products Partners and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Please read “Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” These potential conflicts include, among others, the following situations:

 

 

 

 

 

 

 

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that is available for distribution to our unitholders.

 

 

 

 

 

 

 

 

See Item 13 of this annual report for additional information regarding our relationships with EPCO and Enterprise Products Partners.

 

We may be limited in our ability to consummate transactions, including acquisitions with affiliates of our general partner.

 

We will have inherent conflicts of interest with affiliates of our general partner, including Enterprise Products Partners and TEPPCO. These conflicts may cause the Audit, Conflicts and Governance Committees of these entities not to approve, or unitholders of these entities to dispute, any transactions that may be proposed or consummated between or among us and these affiliates. This may inhibit or prevent us from consummating transactions, including acquisitions, with them.

 

EPCO’s employees may be subjected to conflicts in managing our business and the allocation of time and compensation costs between our business and the business of EPCO and its other affiliates.

 

We have no officers or employees and rely solely on officers of our general partner and employees of EPCO. Certain of our officers are also officers of EPCO and other affiliates of EPCO. These relationships may create conflicts of interest regarding corporate opportunities and other matters, and the resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping officers allocate their time among us, EPCO and other affiliates of EPCO. These officers face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

 

We have entered into an administrative services agreement that governs business opportunities among entities controlled by EPCO, which includes us and our general partner, Enterprise GP Holdings and its general partner, Enterprise Products Partners and its general partner and TEPPCO and its general partner. For information regarding how business opportunities are handled within the EPCO group of companies, see Item 13 of this annual report.

 

We do not have an independent compensation committee, and aspects of the compensation of our executive officers and other key employees, including base salary, are not reviewed or approved by our

 

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independent directors. The determination of executive officer and key employee compensation could involve conflicts of interest resulting in economically unfavorable arrangements for us.

 

An affiliate of Enterprise Products Partners has the power to appoint and remove our directors and management.

 

Because EPOLP owns 100% of DEP GP, it has the ability to elect all the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. Furthermore, the goals and objectives of EPOLP relating to us may not be consistent with those of a majority of the public unitholders.

 

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

 

If at any time our general partner and its affiliates own 80% or more of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of:

 

 

 

As a result, our unitholders may be required to sell their common units at a price that is less than the initial offering price or, because of the manner in which the purchase price is determined, at a price less than the then current market price of our common units. In addition, this call right may be exercised at an otherwise undesirable time or price and unitholders may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units or other equity securities and exercising its call right. If our general partner exercised its call right, the effect would be to take us private and, if our common units were subsequently deregistered, we might no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. As of March 31, 2007, affiliates of Enterprise Products Partners, which owns our general partner, owned approximately 26.4% of our outstanding common units.

 

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

 

 

 

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potential conflict of interest transaction will be conclusive and binding on all persons (including all partners) and will not constitute a breach of the partnership agreement or any standard of care or duty imposed by law;

 

 

 

 

 

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

 

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could lower the trading price of our common units.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, is chosen entirely by its owners and not by the unitholders. Furthermore, even if our unitholders were dissatisfied with the performance of our general partner, they will, practically speaking, have no ability to remove our general partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a control premium in the trading price.

 

The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner. Enterprise Products Partners and its affiliates currently own approximately 26.4% of our outstanding common units.

 

We may issue additional units without our unitholders’ approval, which would dilute our unitholders’ ownership interests.

 

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give unitholders the right to approve our issuance of equity securities ranking junior to our common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to our common units.

 

The issuance by us of additional common units or other equity securities will have the following effects:

 

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

 

Our partnership agreement restricts unitholders’ voting rights by providing that any common units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting common unitholders’ ability to influence the manner or direction of management.

 

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to our unitholders.

 

We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets, other than the ownership interests, in our subsidiaries and joint ventures. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and joint ventures and their ability to distribute funds to us. The ability of our subsidiaries and joint ventures to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies. For example, all cash flows from Evangeline are currently used to service its debt.

 

Affiliates of Enterprise Products Partners currently own a 34% minority equity interest in all of our operating subsidiaries and have a right of first refusal to acquire these subsidiaries or their material assets if we desire to sell them, other than inventory and other assets sold in the ordinary course of business. These rights may adversely affect our ability to dispose of these assets. In addition, our ownership interest in Mont Belvieu Caverns may be diluted, and the cash flow from our NGL & Petrochemical Storage Services segment may be reduced, if we do not contribute our proportionate share of any future costs to fund expansion projects at Mont Belvieu Caverns.

 

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

 

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our common units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per common unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

 

Cost reimbursements to EPCO and its affiliates will reduce cash available for distribution to our unitholders.

 

Prior to making any distribution on our common units, we will reimburse EPCO and its affiliates for all expenses they incur on our behalf, including allocated overhead. These amounts will include all

 

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costs incurred in managing and operating us, including costs for rendering administrative staff and support services to us, and overhead allocated to us by EPCO. See Item 13 of this annual report for more information. The payment of these amounts, including allocated overhead, to EPCO and its affiliates could adversely affect our ability to make distributions to our unitholders.

 

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

 

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. Unitholders could have unlimited liability for our obligations if a court or government agency determined that:

 

 

 

Unitholders may have liability to repay distributions.

 

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

 

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of DEP GP or EPOLP to transfer their equity interests in our general partner or our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to influence the decisions taken by the board of directors and officers of our general partner.

 

 

 

 

 

 

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Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash distributions to our unitholders would be substantially reduced.

 

The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this matter.

 

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

 

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to a material amount of entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states (including Texas) are evaluating ways to enhance state-tax collections. For example, our operating subsidiaries will be subject to a newly revised Texas franchise tax (the “Texas Margin Tax”) on the portion of their revenue that is generated in Texas beginning for tax reports due on or after January 1, 2008. Specifically, the Texas Margin Tax will be imposed at a maximum effective rate of 0.7% of the operating subsidiaries’ gross revenue that is apportioned to Texas. If any additional state were to impose an entity-level tax upon us or our operating subsidiaries, the cash available for distribution to our common unitholders would be reduced.

 

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contests will be borne by our unitholders and our general partner.

 

The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne indirectly by our unitholders and our general partner.

 

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

 

Common unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.

 

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

 

If a common unitholder sells common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income a unitholder is allocated by us, which decreases the unitholder’s tax basis in a common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the unitholder’s tax basis in that common

 

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unit, even if the price the unitholder receives is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to a unitholder.

 

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

 

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

 

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could result in a decrease in the value of our common units.

 

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could decrease the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the common unitholder’s tax returns.

 

Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

 

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, they may be subject to penalties for failure to comply with those requirements. We initially own property or conduct business in Louisiana and Texas. We may own property or conduct business in other states or foreign countries in the future. It is the responsibility of the common unitholders to file all United States federal, state and local tax returns.

 

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

 

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

 

Item 1B. Unresolved Staff Comments.

 

 

 

 

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Item 3. Legal Proceedings.

 

On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activity.

 

In 1997, Acadian Gas and numerous other energy companies were named as defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to under report the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the U.S. government should have received had the volume and heating value been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). On October 20, 2006, the U.S. District Court dismissed all of Grynberg’s claims with prejudice. We expect Grynberg to appeal.

We are not aware of any other significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

 

Item 4. Submission of Matters to a Vote of Unitholders.

 

 

 

PART II

 

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

Equity Securities.

 

Market Information

 

On February 5, 2007, we completed our initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit. Our common units have been listed on the NYSE, under the ticker symbol “DEP.” At December 31, 2006, our equity securities were not listed on any exchange or traded on any public trading market.

 

Our initial public offering generated net proceeds to us of $291.3 million. This initial public offering was made pursuant to a registration statement on Form S-1 declared effective by the SEC on January 30, 2007. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, we distributed $260.6 million of these net proceeds to EPOLP along with $198.9 million in borrowings under our credit facility and a final amount of 5,371,571 our common units. Lehman Brothers Inc. and UBS Securities LLC acted as representatives of the underwriters and joint book-running managers for our initial public offering.

 

As of March 21, 2007, there were approximately 13 unitholders of record of our common units.

 

 

 

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Item 6. Selected Financial Data.

 

We were formed by Enterprise Products Partners on September 29, 2006; therefore, we do not have any historical financial statements prior to our formation. The following tables set forth, for the periods and at the dates indicated, the selected historical combined financial and operating data of Duncan Energy Partners Predecessor. The financial and operating data of Duncan Energy Partners Predecessor was derived from the books and records of Enterprise Products Partners and should be read in conjunction with the audited combined financial statements of Duncan Energy Partners Predecessor (see Item 8 of this annual report) and with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (see Item 7 of this annual report).

 

 

 

 

 

 

 

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The historical combined financial statements included in this annual report reflect assets, liabilities and operations contributed to us by Enterprise Products Partners and various wholly owned subsidiaries upon the closing of our initial public offering. We refer to these assets, liabilities and operations as the assets, liabilities and operations of Duncan Energy Partners Predecessor. The following discussion analyzes the financial condition and results of operations of Duncan Energy Partners Predecessor, which reflects ownership of 100% of the assets, liabilities and operations contributed to us. However, we only have a 66% interest in the assets, liabilities and operations being contributed to us and Enterprise Products Partners retains the remaining 34% interest. In addition, there will be changes to such historical operations and certain agreements as discussed in Note 10 of Notes to Combined Financial Statements of Duncan Energy Partners Predecessor. The following discussion of the financial condition and results of operations for Duncan Energy Partners Predecessor should be read in conjunction with the historical combined financial statements and notes of Duncan Energy Partners Predecessor included elsewhere in this annual report on Form 10-K.

 

Overview of Business

 

We are a Delaware limited partnership formed by Enterprise Products Partners in September 2006 to acquire, own and operate a diversified portfolio of midstream energy assets. For the periods discussed below, our operations were organized into the following three business segments:

 

 

 

 

Our DEP South Texas NGL Pipeline System became operational in January 2007. This business is accounted for under a fourth reporting segment, NGL Pipeline Services. The DEP South Texas NGL Pipeline System consists of a 286-mile pipeline system used to transport NGLs from two of Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas and related interconnections. The historical combined financial statements of Duncan Energy Partners Predecessor do not include any results of operations for this pipeline segment.

 

Capital Spending

 

We are committed to the long-term growth and viability of Duncan Energy Partners. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures with industry partners. We believe that we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected future production increases from the deepwater Gulf of Mexico.

 

The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. For example, our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation through its Office of Pipeline Safety. This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs. In connection with the regulations for hazardous liquid pipelines, we developed a pipeline integrity management program in 2002. In connection with the regulations for natural

 

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gas pipelines, we developed a pipeline integrity management program in 2004.

 

The following table summarizes our expenditures for pipeline integrity costs for the periods indicated (dollars in thousands):

 

 

We expect our net cash outlay for pipeline integrity program expenditures to approximate $4.3 million for 2007.

 

Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:

 

 

 

During 2006, our capital expenditures, including sustaining and growth capital expenditures, totaled $106.4 million. We have budgeted sustaining capital expenditures of $9.4 million for the year ending December 31, 2007. We expect the cost to complete the planned expansion of our DEP South Texas NGL Pipeline System and Mont Belvieu brine production and above-ground storage projects will aggregate $46.3 million, of which our 66% share is approximately $30.6 million. We will use cash on hand from the proceeds of our initial public offering to fund our share of these planned expansion costs and Enterprise Products Partners will make a capital contribution to South Texas NGL and Mont Belvieu Caverns for its 34% share of such costs.

 

We are evaluating several expansion projects at our Mont Belvieu facilities. The projects currently contemplated may be started during 2007 and cost in the range of $25 to $75 million. Additional expenditures of up to $200 million may be made during 2008 and 2009. Pursuant to the Mont Belvieu Caverns limited liability company agreement, EPOLP may, in its sole discretion, fund a portion of any costs related to these projects. We cannot assure you that we will pursue any expansion projects, but if we do, we expect to finance such projects through borrowings under our revolving credit facility, the issuance of debt or additional equity, or contributions from EPOLP. For a further description of our agreements with Enterprise Products Partners relating to potential expansion opportunities, see Item 13 of this annual report.

 

At December 31, 2006 we had $11.3 million in outstanding purchase commitments. These commitments primarily relate to our announced expansions of the DEP South Texas NGL Pipeline System and the Mont Belvieu Caverns’ storage facility, both of which are expected to be completed during 2007.

 

Results of Operations

 

We classify our midstream energy operations in three reportable business segments: NGL & Petrochemical Storage Services, Natural Gas Pipelines & Services, and Petrochemical Pipeline Services. NGL Pipeline Services will be reflected as our fourth business segment to encompass our South Texas NGL pipeline business, which commenced operations in January 2007. Our business segments are

 

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generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.

 

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

 

We define total (or combined) segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) gains and losses on the sale of assets; and (iii) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of any intersegment and intrasegment transactions. Our combined revenues reflect the elimination of all material intercompany transactions.

 

We include equity earnings from Evangeline in our measurement of segment gross operating margin and operating income. Our equity investment in Evangeline is a vital component of our business strategy and important to the operations of Acadian Gas. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Evangeline performs complementary roles to the other business operations of Acadian Gas. As circumstances dictate, we may increase our ownership interest in Evangeline or make other equity method investments.

 

For additional information regarding our business segments, see Note 11 of the Notes to Combined Financial Statements of Duncan Energy Partners Predecessor included under Item 8 of this annual report on Form 10-K.

 

Selected Volumetric Data

 

 

 

 

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Comparison of Results of Operations – Duncan Energy Partners Predecessor

 

The following table summarizes the key components of our combined results of operations for the periods indicated (dollars in thousands):

 

 

Our gross operating margin by business segment and in total is as follows for the periods indicated (dollars in thousands):

 

 

For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before provision for income taxes and the cumulative effect of changes in accounting principles, see “Other Items – Non-GAAP reconciliations” included within this Item 7.

 

The following table summarizes the contribution to combined revenues from each business segment during the periods indicated (dollars in thousands):

 

 

Comparison of Year Ended December 31, 2006 with Year Ended December 31, 2005

 

Combined revenues for 2006 were $924.5 million compared to $953.4 million for 2005. The decrease in combined revenues year-to-year is primarily due to lower revenues associated with natural gas marketing activities. Revenues from the sale of natural gas decreased $41.9 million year-to-year primarily due to lower natural gas sales prices. Revenues from our NGL and petrochemical storage business increased $6.3 million year-to-year primarily due to higher excess storage and throughput fee revenues. Revenues from propylene transportation increased $5.2 million year-to-year due to higher transportation volumes in 2006 relative to 2005.

 

Combined operating costs and expenses were $867.1 million for 2006 compared to $909.0 million for 2005. The year-to-year decrease in combined costs and expenses is primarily due to a decrease in the cost of sales associated with our natural gas marketing activities. The cost of sales of our natural gas marketing activities decreased $41.3 million year-to-year primarily due to lower natural gas prices.

 

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General and administrative costs decreased $1.0 million year-to-year.

 

Changes in our combined revenues and costs and expenses year-to-year are explained in part by changes in energy commodity prices. In general, higher natural gas prices result in an increase in our combined revenues attributable to the sale of natural gas by Acadian Gas; however, these same commodity prices also increase the associated cost of sales as purchase prices rise. The market price of natural gas (as measured at Henry Hub) averaged $7.24 per MMBtu for 2006 versus $8.64 per MMBtu for 2005.

 

To a lesser extent, changes in our revenues and costs and expenses are attributable to demand for NGL and petrochemical storage services and activity on our propylene pipelines. Demand for storage services affects the reservation, excess storage and throughput fees earned by our NGL and petrochemical storage business. In turn, demand for our storage services is driven by factors such as demand for petrochemical feedstocks by the petrochemical industry and the quantity of NGLs extracted from natural gas streams at regional gas processing facilities.

 

Equity earnings from Evangeline were $1.0 million for 2006 compared to $0.3 million for 2005. The increase in equity earnings year-to-year is primarily due to higher natural gas sales margins in 2006 relative to 2005. Also, equity earnings from our investment in Evangeline increased $0.2 million year-to-year due to an increase in Evangeline’s interest income. Evangeline earns interest income on restricted cash balances held in connection with its Series B senior secured notes. For more information regarding Evangeline’s debt obligations, see “Other Items” below.

 

Operating income for 2006 was $54.9 million compared to $40.2 million for 2005. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to the $14.7 million increase in operating income year-to-year. Interest expense for 2005 includes $0.5 million of accrued interest related to a potential assessment for a state sales tax dispute. The interest expense accrual was reversed and reflected as interest income in 2006 upon settlement of the dispute.

 

As a result of the items noted in the previous paragraphs, our combined net income increased $16.2 million year-to-year to $55.3 million in 2006 compared to $39.1 million in 2005. Net income for both years includes the recognition of non-cash amounts related to the cumulative effect of changes in accounting principles. For additional information regarding the cumulative effect of changes in accounting principles we recorded in 2006 and 2005, see “Other Items” below.

 

The following information highlights significant year-to-year variances in gross operating margin by business segment.

 

NGL & Petrochemical Storage Services. Gross operating margin from this business segment was $23.9 million for 2006 compared to $16.6 million for 2005. Revenues increased $6.3 million year-to-year primarily due to higher excess storage and throughput fees and brine production revenues. Operating costs and expenses decreased $1.0 million year-to-year attributable to reduced measurement losses in 2006 compared to 2005, which were partially offset by higher utility and maintenance costs.

 

Storage revenues for 2006 were $5.2 million higher than 2005 primarily due to an increase in excess storage and throughput fee revenues. These revenues were higher year-to-year due to an increase in storage volumes. We attribute the increase in storage volumes to strong demand for petrochemical feedstocks by the petrochemical industry and improved NGL processing economics. Strong NGL processing economics in recent years have increased the quantity of NGLs extracted from natural gas streams at regional gas processing facilities, which increases the demand for storage services. Also, brine production revenues increase $1.1 million year-to-year, which reflects contractual changes made to the sales agreements with our customers during 2006.

 

Natural Gas Pipelines & Services. Gross operating margin from this business segment was $20.1 million for 2006 compared to $18.9 million for 2005, a $1.2 million increase. Natural gas throughput volumes increased to 759 BBtu/d during 2006 from 640 BBtu/d in 2005. A $2.6 million increase in segment gross operating margin year-to-year attributable to the collection of a contingent asset related to a

 

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prior business acquisition was partially offset by a charge of $1.8 million for an imbalance revaluation. Also, equity earnings from our investment in Evangeline increased $0.6 million year-to-year.

 

Petrochemical Pipeline Services. Gross operating margin from this business segment was $35.7 million for 2006 compared to $28.6 million for 2005. Petrochemical transportation volumes were 37 MBPD during 2006 versus 33 MBPD during 2005. Transportation revenues increased $5.2 million year-to-year attributable to higher transportation volumes on our Lou-Tex Propylene Pipeline. Propylene transportation volumes were lower in 2005 relative to 2006 due to the effects of Hurricanes Katrina and Rita. Operating costs and expenses decreased $1.9 million year-to-year primarily due to a reduction in property taxes associated with the Lou-Tex Propylene Pipeline. During 2006, we successfully negotiated a lower property tax rate with the Louisiana state taxing authority, which provided an annual benefit of approximately $1.9 million in 2006.

 

Comparison of Year Ended December 31, 2005 with Year Ended December 31, 2004

 

Combined revenues for 2005 were $953.4 million compared to $748.9 million for 2004. The year-to-year increase in combined revenues is primarily due to higher natural gas sales prices during 2005 relative to 2004, which accounted for a $208.2 million increase in combined revenues associated with natural gas marketing activities.

 

Combined operating costs and expenses for 2005 were $909.0 million compared to $685.5 million for 2004. The year-to-year increase in combined costs and expenses is primarily due to an increase in the cost of sales associated with natural gas marketing activities. Such costs increased $213.0 million year-to-year as a result of higher natural gas prices. General and administrative costs decreased $1.0 million year-to-year.

 

Changes in our combined revenues and costs and expenses year-to-year are explained in part by changes in energy commodity prices. In general, higher natural gas prices result in an increase in our combined revenues attributable to the sale of natural gas by Acadian Gas; however, these same commodity prices also increase the associated cost of sales as purchase prices rise. The Henry Hub market price of natural gas averaged $8.64 per MMBtu during 2005 versus $6.13 per MMBtu during 2004.

 

Operating income for 2005 was $40.2 million compared to $58.2 million for 2004. Collectively, the aforementioned changes in revenues and costs and expenses resulted in an $18.0 million decrease in operating income year-to-year. Interest expense for 2005 includes $0.5 million of accrued interest related to a potential assessment for a state sales tax dispute.

 

As a result of the items noted in the previous paragraphs, our combined net income decreased $19.0 million year-to-year to $39.1 million in 2005 compared to $58.1 million in 2004. Net income for 2005 includes a $0.6 million non-cash charge for the cumulative effect of change in accounting principle related to asset retirement obligations. For additional information regarding the cumulative effect of change in accounting principle we recorded in 2005, see “Other Items” below.

 

The following information highlights significant year-to-year variances in gross operating margin by business segment:

 

NGL & Petrochemical Storage Services. Gross operating margin from this business segment was $16.6 million for 2005 compared to $19.8 million for 2004. Revenues increased $3.3 million year-to-year primarily due to higher excess storage and throughput fee revenues. These revenues were higher in 2005 compared to 2004 due to an increase in storage volumes, which resulted from strong demand for petrochemical feedstocks by the petrochemical industry and improved NGL processing economics. The $3.3 million increase in revenues was offset by a $6.0 million year-to-year increase in operating costs and expenses primarily due to higher utility costs and higher measurement losses recognized in 2005.

 

Historically, operating costs and expenses of our NGL and petrochemical storage business have been affected each period by measurement gains and losses. Operating costs and expenses reflect

 

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measurement losses of $5.2 million for 2005 compared to losses of $0.4 million for 2004. Prospectively, effective concurrent with the closing of our initial public offering, we will specifically allocate to Enterprise Products Partners any items of income and gain or loss and deduction relating to net measurement gains and losses. Accordingly, in the future, these measurement gains and losses should not affect our net income or have a significant impact on us with respect to our cash flows or operating activities.

 

Natural Gas Pipelines & Services. Gross operating margin from this business segment was $18.9 million for 2005 compared to $25.3 million for 2004. Natural gas throughput was 640 Bbtu/d during 2005 compared to 645 Bbtu/d during 2004. Gross operating margin decreased $6.4 million year-to-year primarily due to lower margins on natural gas sales during 2005 relative to 2004. In general, Acadian Gas purchases natural gas at prices that are based upon the Henry Hub index. In turn, Acadian Gas generally wholesales natural gas to its customers at the Henry Hub price plus a contractual margin. Acadian Gas’ natural gas sales contract with Evangeline contains a provision whereby a portion of the contractual margin is determined through a comparison of (i) Acadian Gas’s annual weighted average natural gas purchase cost to (ii) a benchmark determined by reference to a weighted average grouping of natural gas market indices. As a result of this benchmarking mechanism, we realized $4.8 million in higher natural gas sales margins in 2004 relative to 2005. In addition, operating costs and expenses increased $1.7 million year-to-year primarily due to higher sales tax and pipeline integrity costs during 2005 as compared to 2004. Equity earnings from our investment in Evangeline increased $0.1 million year-to-year.

 

Petrochemical Pipeline Services. Gross operating margin from this business segment was $28.6 million for 2005 compared to $36.9 million for 2004. Petrochemical transportation volumes decreased to 33 MBPD during 2005 from 39 MBPD during 2004. Gross operating margin decreased $8.3 million year-to-year primarily due to reduced transportation volumes on our Lou-Tex Propylene Pipeline. Lower transportation volumes accounted for $6.8 million of the year-to-year decrease in gross operating margin. In addition, operating costs and expenses increased $1.1 million year-to-year primarily due to higher pipeline integrity costs during 2005 compared to 2004.

 

Natural Gas Supply and Outlook

 

We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States, including Texas and Louisiana, as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. A number of the areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

 

While we anticipate continued high levels of exploration and production activities in a number of the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.

 

Factors Affecting Comparability of Future Results

 

Our discussion of the financial condition and results of operations for Duncan Energy Partners Predecessor should be read in conjunction with the historical combined financial statements and Notes to Combined Financial Statements of Duncan Energy Partners Predecessor included under Item 8 of this annual report. Our future results could differ materially from our historical results due to a variety of factors, including the following:

 

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Partial Ownership of Operating Assets.  As a result of contributions completed in connection with our initial public offering, we own 66% of the equity interests in the subsidiaries that hold our operating assets, and affiliates of Enterprise Products Partners continue to own the remaining 34%. The historical combined financial statements of Duncan Energy Partners Predecessor were prepared from Enterprise Products Partners’ separate historical accounting records related to our operating assets. Accordingly, our discussion reflects 100% of the results of operations of these assets.

 

No Historical Results for Our NGL Pipeline Services Segment.  Our discussion of historical results does not reflect any operations related to our 286-mile DEP South Texas NGL Pipeline System, which did not commence operations until January 2007. The primary component of this pipeline system was acquired in August 2006, at which time the seller informed us that no discrete and separable financial information existed for the pipeline. In addition, the seller had previously utilized the pipeline for a different product and the pipeline was out of service when we acquired it. There is no financial data available regarding the prior use of this pipeline segment by the sellers that would be meaningful to our investors. In addition, such data, if available, would not assist investors in understanding either the evolution of the business (which is a new NGL transportation network) or the track record of management (which will be different).

 

Increase in Outstanding Indebtedness.  Historically, we have not had any consolidated indebtedness and, therefore, we have not had consolidated interest expense. We borrowed $200.0 million under a revolving credit facility at the time of our initial public offering, of which $198.9 million was paid to EPOLP in connection with its contribution of certain operating assets to us. These additional borrowings are expected to increase interest expense by approximately $13 million per year assuming an interest rate of 6.5% and normal amortization of debt issuance costs.

 

Increased Storage Fees.  As a result of contracts executed in connection with our initial public offering, we increased certain storage fees charged to Enterprise Products Partners for use of our facilities owned by Mont Belvieu Caverns. Historically, such intercompany charges were below market and eliminated in the consolidated revenues and costs and expenses of Enterprise Products Partners. Prospectively, such rates will be market-based.

 

Special Allocation of Storage Well and Operational Measurement Gains and Losses.  Storage well measurement gains and losses occur when product movements into a storage well are different than those redelivered to customers. In general, such variations result from difficulties in precisely measuring significant volumes of liquids at varying flow rates and temperatures. It is expected that substantially all product delivered into a storage well will be withdrawn over time. As a result, a storage well measurement loss in one period is expected to be offset by a storage well measurement gain in a subsequent period, unless product is physically lost in a well due to problems with cavern integrity.

 

We are responsible for product losses attributable to cavern integrity events. We did not experience any cavern integrity events during the three years ended December 31, 2006.

 

Historically, storage well measurement gains and losses, and the associated storage imbalance reserve account, have been included in our predecessor financial statements. Since we expect that storage well measurement gains and losses offset each other over time, we have historically charged storage well gains or losses to a storage imbalance reserve account during the month such imbalances occur based on current pricing. This reserve has been increased by the impact of storage well measurement gains and decreased by storage well measurement losses. On an annual basis, the storage imbalance reserve account has been reviewed for reasonableness based on historical storage well measurement gains and losses and adjusted accordingly through a charge to earnings. At December 31, 2006 and 2005, our storage imbalance reserve account was $4.0 million and $4.5 million, respectively. Net storage well measurement losses of $0.5 million, $2.0 million and $2.2 million were charged to the reserve during the years ended December 31, 2006, 2005 and 2004, respectively. Operating costs and expenses reflect storage well measurement loss accruals of $3.1 million and $0.6 million for the years ended December 31, 2005 and 2004, respectively. We did not accrue for any storage well measurement losses for the year ended December 31, 2006.

 

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In connection with storage agreements for a variety of products entered into between Enterprise Products Partners and Mont Belvieu Caverns effective concurrently with the closing of our initial public offering, Enterprise Products Partners has agreed to absorb all storage well measurement gains and losses.

 

Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. Many of our customer storage arrangements allow us to retain a small amount of product to help offset any operational measurement losses. These measurement variances are estimated and settled each reporting period at current prices as a net credit or charge to our operating costs and expenses. We do not own physical inventory volumes. We recorded net operational measurement gains of $0.2 million during each of the years ended December 31, 2006 and 2004. We recorded net operational measurement losses of $2.1 million during the year ended December 31, 2005.

 

The Mont Belvieu Caverns’ limited liability company agreement allocates to Enterprise Products Partners any items of income or loss relating to net operational measurement gains and losses, including amounts that Mont Belvieu Caverns may retain as handling losses. As such, Enterprise Products Partners is required each period to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive distributions from Mont Belvieu Caverns for net operational measurement gains. We continue to record operational measurement gains and losses associated with the operation of our Mont Belvieu storage facility. However, these operational measurement gains and losses should not affect our net income or have a significant impact on us with respect to the timing of our net cash provided by operating activities and, accordingly, we have not established a reserve for operational measurement losses on our balance sheet.

 

Decrease in Propylene Transportation Rates.  The transportation fees we currently receive from customers utilizing our Lou-Tex Propylene and Sabine Propylene Pipelines are lower than those we realized in historical periods. Historically, Enterprise Products Partners was the shipper of record on these pipelines, and we charged Enterprise Products Partners the maximum tariff rate for using these assets. Enterprise Products Partners then contracted with third parties to ship volumes on these pipelines under product exchange agreements. In general, the revenues recognized by Enterprise Products Partners in connection with these exchange agreements were lower than the maximum tariff rate it paid us. In connection with our initial public offering, Enterprise Products Partners assigned its third party product exchange agreements to us. Accordingly, the transportation fees we receive for use of our Lou-Tex Propylene and Sabine Propylene Pipelines are less than the historical fees we received from Enterprise Products Partners.

 

Additional General and Administrative Expenses.  We expect to incur approximately $2.5 million in additional general and administrative expenses as a result of becoming a publicly traded entity. These costs include fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and accounting and legal services. These costs also include estimated related party amounts payable to EPCO in connection with the administrative services agreement. For additional information regarding the administrative services agreement, see Item 13 of this annual report.

 

Liquidity and Capital Resources

 

Our primary cash requirements, in addition to normal operating and general and administrative expenses are for capital expenditures, business acquisitions, distributions to partners and debt service. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with cash flows from operations and borrowings under the revolving credit facility. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources (either separately or in combination), including cash flows from operations, borrowings under our revolving credit facility, and the issuance of additional equity or debt securities. We expect to fund cash distributions to partners primarily with cash flows from operations. Debt service requirements are expected to be funded by cash flows from operations or refinancing arrangements.

 

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Initial Public Offering

 

On February 5, 2007, we completed our initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at a price of $21.00 per unit, which generated net proceeds of $291.3 million after deducting applicable underwriting discounts, commissions, structuring fees and other offering expenses. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, we distributed $260.6 million of these net proceeds to EPOLP, along with $198.9 million in borrowings under our revolving credit facility (see below) and a final amount of 5,351,571 of our common units. We used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units we had originally issued to EPOLP, resulting in the final amount of 5,351,571 common units beneficially owned by EPOLP. EPOLP used the cash it received from us to temporarily reduce amounts outstanding under its revolving credit facility.

 

Revolving Credit Facility

 

We have entered into a $300.0 million revolving credit facility, all of which may be used for letters of credit, with a $30.0 million sublimit for Swingline loans. At the closing of our initial public offering, we made an initial draw of $200.0 million under this facility to fund the $198.9 million cash distribution to EPOLP and the remainder to pay debt issuance costs. This credit facility matures in February 2011 and will be used by us in the future to fund working capital requirements, make payments in connection with acquisitions and for general partnership purposes. We may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). The revolving credit facility is also available to help fund distributions. We can increase the borrowing capacity under our revolving credit facility, without consent of the lenders, by an amount not exceeding $150.0 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. No lender is required to increase its commitment, unless it agrees to do so in its sole discretion.

 

Our revolving credit facility offers the following unsecured loans, each having different minimum amount and interest requirements:

 

 

 

 

Borrowings outstanding under our revolving credit facility may be prepaid in whole or in part at any time upon same day notice, in a minimum amount of $3.0 million with respect to LIBOR loans and $1.0 million with respect to Base Rate Loans (or any lesser amount equal to outstanding borrowings), and integral multiples of $1.0 million above that amount. Unless LIBOR loans are prepaid on interest payment dates, breakage costs could be incurred.

 

The revolving credit facility requires us to maintain a leverage ratio for the prior four fiscal quarters of not more than 4.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007; provided, upon the closing of a permitted acquisition, such ratio shall not exceed (a) 5.25 to 1.00 at the last day of the fiscal quarter in which such specified acquisition occurred and at the last day of each of the two fiscal quarters following the fiscal quarter in which such specified acquisition occurred, and (b) 4.75 to 1.00

 

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at the last day of each fiscal quarter thereafter. In addition, prior to obtaining an investment-grade rating by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings, our interest coverage ratio, for the prior four fiscal quarters shall not be less than 2.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007.

 

Our revolving credit facility contains various operating and financial covenants, including those restricting or limiting our ability, and the ability of certain of our subsidiaries, to:

 

 

 

 

 

 

 

 

 

 

If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following is an event of default under the credit agreement:

 

 

 

 

 

 

 

 

 

 

 

 

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Duncan Energy Partners Predecessor Cash Flows

 

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (dollars in thousands). For information regarding the individual components of our cash flow amounts, please read the Statements of Combined Cash Flows of Duncan Energy Partners Predecessor included elsewhere in this annual report.

 

 

We have operated within the Enterprise Products Partners’ cash management program for all periods presented. For purposes of presentation in the Statements of Combined Cash Flows, cash flows received (or used) in financing activities represent transfers of excess cash from us to Enterprise Products Partners equal to net cash flow provided by operating activities less cash used in investing activities. Such transfers of excess cash are shown as distributions to owners in the Statements of Combined Owners’ Net Investment. Conversely, if cash used in investing activities is greater than net cash flow provided by operating activities, then a deemed contribution by owners is presented. As a result, the combined financial statements do not present cash balances for any of the periods presented.

 

Due to the foregoing method of presentation, our owners were deemed to contribute $44.5 million in 2006 and were deemed to have been paid $21.1 million and $72.5 million in net cash distributions in 2005 and 2004, respectively.

 

Cash used in investing activities primarily represents expenditures for capital projects. Cash used in financing activities generally consists of contributions from and distributions to owners.

 

The following information highlights the significant year-to-year variances in our cash flow amounts:

 

Comparison of Year Ended December 31, 2006 with Year Ended December 31, 2005

 

Operating activities.  Net cash flow provided by operating activities was $61.1 million for 2006 compared to $40.6 million for 2005. The $20.5 million increase in net cash flow provided by operating activities is primarily due to higher earnings for 2006 relative to 2005 and the timing of cash receipts from sales and cash payments for purchases and other expenses between periods. For information regarding changes in revenues and costs and expenses, please read “ Results of Operations” above.

 

Investing activities.  Cash used in investing activities was $105.6 million for 2006 compared to $19.5 million for 2005. The $86.1 million increase in cash used in investing activities is primarily due to expansions of our Mont Belvieu, Texas storage facility and DEP South Texas NGL Pipeline System. During 2006, we spent $71.5 million for the expansion of our storage facility and $19.6 million for additions and modifications of the DEP South Texas NGL Pipeline System.

 

Financing activities.  Net cash contributions from owners were $44.5 million for 2006 compared to net cash distributions to owners of $21.1 million for 2005. The change in financing activities resulted from an increase in cash provided by operating activities and a significant increase in cash used for capital expenditures during 2006 relative to 2005.

 

 

 

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Comparison of Year Ended December 31, 2005 with Year Ended December 31, 2004

 

Operating activities.  Net cash flow provided by operating activities was $40.6 million for 2005 compared to $79.5 million for 2004. The $38.9 million decrease in net cash flow provided by operating activities is primarily due to lower earnings in 2005 relative to 2004 and the timing of cash receipts from sales and cash payments for purchases and other expenses between periods. For information regarding changes in revenues and costs and expenses between the two years, please read “Results of Operations” above.

 

Investing activities.  Cash used in investing activities was $19.5 million for 2005 compared to $6.9 million for 2004. The $12.6 million increase in cash used in investing activities was primarily due to the expansion of brine production and brine storage reservoirs at our Mont Belvieu storage complex.

 

Financing activities.  Net cash distributions to owners were $21.1 million for 2005 compared to $72.5 million for 2004. The change in cash distributions results from a decrease in net cash flow provided by operating activities in 2005 when compared to 2004 combined with an increase in cash used for capital expenditures in 2005 relative to 2004.

 

Critical Accounting Policies

 

In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the estimation risk underlying our most significant financial statement items.

 

Depreciation methods and estimated useful lives of property, plant and equipment

 

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. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Some of these circumstances include changes in laws and regulations relating to restoration and abandonment requirements; changes in expected costs for dismantlement, restoration and abandonment as a result of changes, or expected changes, in labor, materials and other related costs associated with these activities; changes in the useful life of an asset based on the actual known life of similar assets, changes in technology, or other factors; and changes in expected salvage proceeds as a result of a change, or expected change in the salvage market.

 

At December 31, 2006 and 2005, the net book value of our property, plant and equipment was $707.6 million and $512.2 million, respectively. We recorded $21.4 million, $19.2 million and $18.1 million in depreciation expense for the years ended December 31, 2006, 2005 and 2004, respectively.

 

Measuring recoverability of long-lived assets and equity method investments

 

In general, long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand or price of natural gas, oil or NGLs. Long-lived assets with recorded values that are not expected to be recovered through expected future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result

 

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from the use and eventual disposition of the existing asset. Our estimates of such undiscounted cash flows are based on a number of assumptions including anticipated operating margins and volumes; estimated useful life of the asset or asset group; and estimated salvage values. An impairment charge would be recorded for the excess of a long-lived asset’s carrying value over its estimated fair value, which is based on a series of assumptions similar to those used to derive undiscounted cash flows. Those assumptions also include usage of probabilities for a range of possible outcomes, market values and replacement cost estimates.

 

An equity method investment is evaluated for impairment whenever events or changes in circumstances indicate that there is a possible loss in value of the investment other than a temporary decline. Examples of such events include sustained operating losses of the investee or long-term negative changes in the investee’s industry. The carrying value of an equity method investment is not recoverable if it exceeds the sum of the discounted estimated cash flows expected to be derived from the investment. This estimate of discounted cash flows is based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful life of the investment. A significant change in these underlying assumptions could result in our recording an impairment charge.

 

We did not recognize any asset impairment charges during the periods presented. In addition, we did not recognize any impairment charges related to our Evangeline affiliate during the periods presented.

 

Amortization methods and estimated useful lives of qualifying intangible assets

 

The specific, identifiable intangible assets of a business enterprise depend largely upon the nature of its operations. Potential intangible assets include, intellectual property, such as technology, patents, trademarks, trade names, customer contracts and relationships and non-compete agreements, as well as other intangible assets. The method used to value each intangible asset will vary depending upon the nature of the asset, the business in which it is utilized, and the economic returns it is generating or is expected to generate.

 

If our underlying assumptions regarding the estimated useful life of an intangible asset change, then the amortization period for such asset would be adjusted accordingly. Additionally, if we determine that an intangible asset’s unamortized cost may not be recoverable due to impairment, we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the useful life of an intangible asset would increase operating costs and expenses at that time.

 

Our intangible assets consist primarily of renewable storage contracts with various customers that we acquired in connection with the purchase of storage caverns from a third party in January 2002. Due to the renewable nature of these contracts, we amortize them on a straight-line basis over a 35-year period, which is the estimated remaining economic life of the storage assets to which they relate.

 

At December 31, 2006 and 2005, the carrying value of our intangible asset portfolio was $7.0 million and $7.2 million, respectively. We recorded $0.2 million in amortization expense associated with our intangible assets for all periods presented.

 

Our revenue recognition policies and use of estimates for revenues and expenses

 

In general, 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. When sales contracts are settled (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), we record any necessary allowance for doubtful accounts.

 

We make estimates for certain revenue and expense items due to time constraints on the financial accounting and reporting process. At times, we must estimate revenues from a customer before we actually

 

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bill the customer or accrue an expense we incur before physically receiving a vendor’s invoice. Such estimates reverse in the following period and are offset by our recording the actual customer billing and vendor invoice amounts. If the basis of our estimates proves to be substantially incorrect, it could result in material adjustments in results of operations between periods. For all periods presented, our revenue and cost estimates are substantially correct as compared to actual amounts.

 

Natural gas imbalances

 

In the pipeline transportation business, natural gas imbalances frequently result from differences in gas volumes received from and delivered to our customers. Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period. The vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several months. In some cases, settlements of imbalances accumulated over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time. As a result, for gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement. Changes in natural gas prices may impact our estimates.

 

At December 31, 2006 and 2005, our imbalance receivables were $2.6 million and $1.6 million, respectively, and are reflected as a component of “Accounts receivable — trade” on our Combined Balance Sheets. At December 31, 2006 and 2005, our imbalance payable was $0.5 million and $2.9 million respectively, and is reflected as a component of “Accrued gas payables” on our Combined Balance Sheets.

 

Storage well and operational measurement gains and losses

 

Storage well measurement gains and losses occur when product movements into a storage well are different than those redelivered to customers. In general, such variations result from difficulties in precisely measuring significant volumes of liquids at varying flow rates and temperatures. It is expected that substantially all product delivered into a storage well will be withdrawn over time. As a result, a storage well measurement loss in one period is expected to be offset by a storage well measurement gain in a subsequent period, unless product is physically lost in a well due to problems with cavern integrity.

 

We are responsible for product losses attributable to cavern integrity events. We did not experience any cavern integrity events during the three years ended December 31, 2006.

 

Historically, storage well measurement gains and losses, and the associated storage imbalance reserve account, have been included in our predecessor financial statements. Since we expect that storage well measurement gains and losses offset each other over time, we have historically charged storage well gains or losses to a storage imbalance reserve account during the month such imbalances occur based on current pricing. This reserve has been increased by the impact of storage well measurement gains and decreased by storage well measurement losses. On an annual basis, the storage imbalance reserve account has been reviewed for reasonableness based on historical storage well measurement gains and losses and adjusted accordingly through a charge to earnings. At December 31, 2006 and 2005, our storage imbalance reserve account was $4.0 million and $4.5 million, respectively. Net storage well measurement losses of $0.5 million, $2.0 million and $2.2 million were charged to the reserve during the years ended December 31, 2006, 2005 and 2004, respectively. Operating costs and expenses reflect storage well measurement loss accruals of $3.1 million and $0.6 million for the years ended December 31, 2005 and 2004, respectively. We did not accrue for any storage well measurement losses for the year ended December 31, 2006.

 

In connection with storage agreements for a variety of products entered into between Enterprise Products Partners and Mont Belvieu Caverns effective concurrently with the closing of our initial public offering, Enterprise Products Partners has agreed to absorb all storage well measurement gains and losses.

 

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Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. Many of our customer storage arrangements allow us to retain a small amount of product to help offset any operational measurement losses. These measurement variances are estimated and settled each reporting period at current prices as a net credit or charge to our operating costs and expenses. We do not own physical inventory volumes. We recorded net operational measurement gains of $0.2 million during each of the years ended December 31, 2006 and 2004. We recorded net operational measurement losses of $2.1 million during the year ended December 31, 2005.

 

The Mont Belvieu Caverns’ limited liability company agreement allocates to Enterprise Products Partners any items of income or loss relating to net operational measurement gains and losses, including amounts that Mont Belvieu Caverns may retain as handling losses. As such, Enterprise Products Partners is required each period to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive distributions from Mont Belvieu Caverns for net operational measurement gains. We continue to record operational measurement gains and losses associated with the operation of our Mont Belvieu storage facility. However, these operational measurement gains and losses should not affect our net income or have a significant impact on us with respect to the timing of our net cash flow provided by operating activities and, accordingly, we have not established a reserve for operational measurement losses on our balance sheet.

 

Other Items

 

Contractual Obligations

 

The following table summarizes our significant contractual obligations at December 31, 2006 (dollars in thousand). For additional information regarding these significant contractual obligations, see Note 12 of the Notes to the Combined Financial Statements of Duncan Energy Partners Predecessor included under Item 8 of this annual report.

 

 

Off-Balance Sheet Arrangements

 

At December 31, 2006, long-term debt for Evangeline consisted of: (i) $18.2 million in principal amount of 9.9% fixed interest rate senior secured notes due December 2010 (the “Series B” notes); and (ii) a $7.5 million subordinated note payable to The Louisiana Land and Exploration Company.

 

The Series B notes are collateralized by the following: (i) Evangeline’s property, plant and equipment; (ii) proceeds from Evangeline’s Entergy Louisiana natural gas sales contract; and (iii) a debt

 

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service reserve requirement.

 

Scheduled principal repayments on the Series B notes are $5.0 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios. Evangeline was in compliance with such covenants during the periods presented.

 

Evangeline incurred the LL&E Note obligations in connection with its acquisition of the Entergy natural gas sales contract in 1991. The LL&E Note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at a LIBOR rate plus 0.5%. Variable interest rates charged on this note at December 31, 2006, 2005 and 2004 were 6.08%, 4.23% and 1.83%, respectively. At December 31, 2006, 2005 and 2004, the amount of accrued but unpaid interest on the LL&E Note is approximately $7.9 million, $7.1 million and $6.6 million, respectively.

 

We have no off-balance sheet arrangements, as described in Item 303(a)(4)(ii) of Regulation S-K, that have or are reasonably expected to have a material current or future effect on our financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

 

Summary of Related Party Transactions

 

We have extensive and ongoing business relationships with EPCO and Enterprise Products Partners and each of their affiliates. For additional information regarding our related party transactions, see Note 10 of the Notes to Combined Financial Statements included under Item 8 of this annual report. For information regarding certain business relationships and related transactions, see Item 13 of this annual report.

 

Non-GAAP reconciliations.

 

A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes and the cumulative effect of changes in accounting principles follows (dollars in thousands):

 

 

Cumulative effect of changes in accounting principles  

 

Our Statements of Combined Operations and Comprehensive Income reflect the following cumulative effects of changes in accounting principles:

 

 

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For additional information regarding these changes in accounting principles, see Note 8 of the Notes to Combined Financial Statements of Duncan Energy Predecessor included under Item 8 of this annual report.

 

Recent Accounting Pronouncements

 

The accounting standard setting bodies and the SEC have recently issued the following accounting guidance that will or may affect our financial statements:

 

 

 

 

 

For additional information regarding these recent accounting developments that may affect our future financial statements, see Note 3 of Duncan Energy Partners Predecessor Notes to Combined Financial Statements included under Item 8 of this annual report.

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 

We use financial instruments in our Natural Gas Pipelines & Services segment to secure certain fixed price natural gas sales contracts (referred to as “customer fixed-price arrangements”). We also enter into a limited number of cash flow hedges in connection with such business. We recognize such instruments on the balance sheet as assets or liabilities based on an instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met.

 

To qualify as a hedge, the item to be hedged must be exposed to commodity price risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate such financial instruments as hedges and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is immediately recognized in earnings. Our customer fixed-price arrangements do not qualify for hedge accounting under SFAS 133; therefore, these instruments are accounted for using a mark-to-market approach each reporting period.

 

If a financial instrument meets those criteria, the instruments gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses on cash flow hedges are reclassified into earnings when the forecasted transaction affects earnings. For additional information regarding our accounting for financial instruments, see Note 5 of the Notes to the Combined Financial Statements of Duncan Energy Partners Predecessor under Item 8 of this annual report.

 

 

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Commodity financial instrument portfolio

 

In addition to its natural gas transportation business, our Natural Gas Pipelines & Services segment engages in the purchase and sale of natural gas to third party customers in the Louisiana area. The price of natural gas fluctuates in response to changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. We may use commodity financial instruments such as futures, swaps and forward contracts to mitigate such risks. In general, the types of risks we attempt to hedge are those related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. The commodity financial instruments we utilize may be settled in cash or with another financial instrument. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

 

Acadian Gas enters into a small number of cash flow hedges in connection with its purchase of natural gas held for sale to third parties. In addition, Acadian Gas enters into a limited number of offsetting financial instruments that effectively fix the price of natural gas for certain of its customers. Historically, the use of commodity financial instruments by Acadian Gas was governed by policies established by the general partner of Enterprise Products Partners. The objective of this policy was to assist Acadian Gas in achieving its profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the general partner. In general, we may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to its commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months.

 

The general partner of Enterprise Products Partners monitored the hedging strategies associated with the physical and financial risks of Acadian Gas (such as those mentioned previously), approved specific activities subject to the policy (including authorized products, instruments and markets) and established specific guidelines and procedures for implementing and ensuring compliance with the policy. Our general partner will continue such policies in the future.

 

The fair value of our commodity financial instrument portfolio was a negligible amount at December 31, 2006 and a liability of $0.1 million at December 31, 2005. We recorded losses of $0.8 million and $0.2 million related to our commodity financial instruments for the years ended December 31, 2006 and 2005, respectively. We recorded a gain of $0.2 million from our commodity financial instruments in 2004.

 

We assess the risk of our commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis applied to this portfolio measures the potential income or loss (i.e., the change in fair value of the portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the date indicated within the following table. The following table presents the effect of hypothetical price movements on the estimated fair value (“FV”) of this portfolio at the dates presented (dollars in thousands):

 

 

Product purchase commitments 

 

Our Natural Gas Pipelines & Services segment has a long-term natural gas purchase contract with a third party. This purchase agreement expires in January 2013. Our purchase price under this contract approximates the market price of natural gas at the time we take delivery of the volumes. For additional information regarding our commitments, please read “Contractual Obligations” under Item 7 of this annual report.

 

 

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Item 8. Financial Statements and Supplementary Data.

 

Duncan Energy Partners Predecessor combined financial statements, together with the independent registered public accounting firm’s report of Deloitte & Touche LLP, begin on page F-1 of this report. In addition, we have included the audited balance sheets of Duncan Energy Partners L.P. and its general partner as of December 31, 2006.

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

 

 

 

Item 9A. Controls and Procedures.

 

Our management, including the chief executive officer (“CEO”) and chief financial officer (“CFO”) of DEP Holdings, LLC, evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting, as of December 31, 2006. This evaluation concluded that our disclosure controls and procedures, are effective to provide us with a reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are designed to provide us with a reasonable assurance that the information accumulated and communicated to our management, including the CEO and CFO of our general partner, as appropriate to allow such persons to make timely decisions regarding required disclosures.

 

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Duncan Energy Partners have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurance of achieving our desired control objectives, and our CEO and CFO have concluded that our disclosure controls and procedures are effective in achieving that level of reasonable assurance as of December 31, 2006.

 

Internal control over financial reporting

 

Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with GAAP. These internal controls over financial reporting were designed under the supervision of our management, including the CEO and CFO of DEP GP, and include policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

 

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a

 

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transition period established by rules of the Securities and Exchange Commission for newly public companies.

 

Changes in internal control over financial reporting during the fourth quarter of 2006

 

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

Item 9B. Other Information.

 

 

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance.

 

General

 

As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for the management or operations of our business. These functions are performed by the employees of EPCO pursuant to an administrative services agreement under the direction of the Board of Directors (the Board) and executive officers of our general partner. For a description of the administrative services agreement, see “Certain Relationships and Related Transactions – Relationship with EPCO” under Item 13 of this annual report.

 

Each member of the Board of our general partner serves until such member’s death, resignation or removal. The executive officers of our general partner are elected for one-year terms and may be removed, with or without cause, only by the Board. Our unitholders do not elect the officers or directors of our general partner. Dan. L. Duncan, through his indirect control of our general partner, has the ability to elect, remove and replace at any time, all of the officers and directors of our general partner.

 

The Board of our general partner has one committee, the Audit, Conflicts and Governance Committee, which we refer to in this annual report as the ACG Committee.

 

Because we are a limited partnership and meet the definition of a “controlled company” under the listing standards of the NYSE, we are not required to comply with certain requirements of the NYSE. Accordingly, we have elected to not comply with Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of our general partner be comprised of a majority of independent directors. In addition, we have elected to not comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of our general partner maintain a Nominating Committee and a Compensation Committee, each consisting entirely of independent directors.

 

Our general partner is liable for all debts we incur (to the extent not paid by us), except to the extent that such indebtedness or other obligations are non-recourse to our general partner. Whenever possible, our general partner intends to make any such indebtedness or other obligations non-recourse to itself.

 

Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent

 

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permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.

 

Corporate Governance

 

We are committed to sound principles of governance. Such principles are critical for us to achieve our performance goals, and maintain the trust and confidence of investors, employees, suppliers, business partners and stakeholders.

 

A key element for strong governance is independent members of the Board of Directors. Pursuant to the NYSE listing standards, a director will be considered independent if the Board determines that he or she does not have a material relationship with our general partner or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with DEP GP or us). Based on the foregoing, the Board has affirmatively determined that William A. Bruckmann, III, Larry J. Casey and Joe D. Havens are “independent” under the NYSE rules.

 

As required by the Sarbanes-Oxley Act of 2002, the SEC adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy a heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Neither our general partner nor any individual member of its ACG Committee has relied on any exemption in the NYSE rules to establish such individual’s independence. Based on the foregoing criteria, the Board has affirmatively determined that all members of its ACG Committee satisfy this heightened independence requirement.

 

Code of Conduct and Ethics and Corporate Governance Guidelines

 

Our general partner has adopted a “Code of Conduct” that applies to all directors, officers and employees. This code sets out our requirements for compliance with legal and ethical standards in the conduct of our business, including general business principles, legal and ethical obligations, compliance policies for specific subjects, obtaining guidance, the reporting of compliance issues and discipline for violations of the code.

 

Our general partner has adopted a code of ethics, the Code of Ethical Conduct for Senior Financial Officers and Managers that applies to our CEO, CFO, Principal Accounting Officer and senior financial and other managers. This code is contained in the “Code of Conduct”. In addition to other matters, this code of ethics establishes policies to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting violations of the code.

 

Governance guidelines, together with committee charters, provide the framework for effective governance. The Board has adopted the “Governance Guidelines of Duncan Energy Partners,” which address several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibility of ACG Committees, the conduct and frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, director orientation and continuing education, and annual self-evaluation of the board. The Board recognizes that effective governance is an on-going process, and thus, the Board will review the Governance Guidelines of Duncan Energy Partners annually or more often as deemed necessary.

 

We provide access through our website at http://www.deplp.com to current information relating to governance, including the Code of Ethical Conduct for Senior Financial Officers and Managers, the Governance Guidelines of Duncan Energy Partners and other matters impacting our governance principles. You may also contact our investor relations department at (866) 230-0745 for printed copies of these documents free of charge.

 

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ACG Committee

 

The sole committee of the Board is its ACG Committee. In accordance with NYSE rules and Section 3(a)(58)(A) of the Securities Exchange Act of 1934, the Board of our general partner has named three of its members to serve on its ACG Committee. The members of the ACG Committee are independent directors, free from any relationship with us or any of our subsidiaries that would interfere with the exercise of independent judgment.

 

The members of the ACG Committee must have a basic understanding of finance and accounting and be able to read and understand fundamental financial statements, and at least one member of the ACG Committee shall have accounting or related financial management expertise. The members of the ACG Committee are Messrs. Bruckmann, Casey and Havens. The Board has affirmatively determined that Mr. Bruckmann satisfies the definition of “audit committee financial expert” as defined in Item 401(h) of Regulation S-K promulgated by the SEC.

 

The ACG Committee’s duties are addressing audit and conflicts-related items and general corporate governance. From an audit and conflicts standpoint, the primary responsibilities of the ACG Committee include:

 

 

 

 

 

 

 

 

Under our partnership agreement, the ACG Committee serves the function of the Audit and Conflicts Committee referred to therein and has the authority to review specific matters as to which the Board believes there may be a conflict of interests in order to determine if the resolution of such conflict proposed by our general partner is fair and reasonable to us. Any matters approved by the ACG Committee are conclusively deemed to be fair and reasonable to our business, approved by all of our partners and not a breach by our general partner or its Board of Directors of any duties they may owe us or our unitholders.

 

Pursuant to its formal written charter, the ACG Committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to our independent public accountants as well as any EPCO personnel whom it deems necessary in fulfilling its responsibilities. The ACG Committee has the ability to retain, at our expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties.

 

The ACG Committee is also appointed by the Board to assist the Board in fulfilling its oversight responsibilities. The ACG Committee’s primary duties and responsibilities are to develop and recommend to the Board a set of governance principles applicable to us, review the qualifications of candidates for Board membership, screen and interview possible candidates for Board membership and communicate with members of the Board regarding Board meeting format and procedures.

 

 

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Executive Sessions of Non-Management Directors

 

The Board holds regular executive sessions in which non-management directors meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. During such executive sessions, one director is designated as the “Presiding Director,” who is responsible for leading and facilitating such executive sessions. The Presiding Director is the Chairman of the ACG Committee.

 

In accordance with the rules of the NYSE, we have designated our toll-free, confidential Hotline as the method for interested parties to communicate with the Presiding Director, alone, or with the non-management Directors of our general partner as a group. All calls to this Hotline are reported to the Chairman of the ACG Committee of our general partner, who is responsible for communicating any necessary information to the other non-management directors as a group. The number of our confidential Hotline is 877-888-0002.

 

Directors and Executive Officers of DEP GP

 

The following table sets forth the name, age and position of each of the directors and executive officers of our general partner at March 31, 2007. Each of the individuals listed below, including Mr. Duncan, is an executive officer of our general partner.

 

 

Dan L. Duncan was elected Chairman and a Director of our general partner in October 2006, Chairman and a Director of EPE Holdings in August 2005 and Chairman and a Director of Enterprise Products GP in April 1998. Mr. Duncan has served as Chairman and a Director of the general partner of EPOLP since December 2003 and as Chairman of EPCO since 1979.

 

Richard H. Bachmann was elected President, Chief Executive Officer and a Director of our general partner in October 2006 and a Director of EPE Holdings and Enterprise Products GP in February 2006. Mr. Bachmann previously served as a Director of Enterprise Products GP from June 2000 to January 2004. Mr. Bachmann was elected Executive Vice President, Chief Legal Officer and Secretary of Enterprise Products GP and of EPCO, and a Director of EPCO, in January 1999. In November 2006, Mr. Bachmann was appointed as an independent manager of Constellation Energy Partners LLC. Mr. Bachmann serves as a member of the audit, compensation and nominating and governance committee of Constellation Energy Partners LLC.

 

Michael A. Creel was elected Executive Vice President, Chief Financial Officer and a Director of our general partner in October 2006. Also, he was elected Executive Vice President of Enterprise Products GP and EPCO in January 2001, after serving as a Senior Vice President of Enterprise Products GP and EPCO from November 1999 to January 2001. Mr. Creel, a certified public accountant, served as Chief Financial Officer of EPCO from June 2000 through April 2005 and was named Chief Operating Officer of EPCO in April 2005. In June 2000, Mr. Creel was also named Chief Financial Officer of Enterprise Products GP. Mr. Creel has served as a Director of the general partner of EPOLP since December 2003, and has served as President, Chief Executive Officer and a Director of EPE Holdings since August 2005. Mr. Creel was elected a Director of Edge Petroleum Corporation (a publicly traded oil and natural gas

 

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exploration and production company) in October 2005 and a Director of Enterprise Products GP in February 2006.

 

Gil H. Radtke was elected Senior Vice President, Chief Operating Officer and a Director of our general partner in October 2006 and Senior Vice President of Enterprise Products GP in February 2002. Mr. Radtke joined Enterprise Products Partners in connection with its purchase of Diamond-Koch’s storage and propylene fractionation assets in January and February 2002. Before joining Enterprise Products Partners, Mr. Radtke served as President of the Diamond-Koch joint venture from 1999 to 2002, where he was responsible for its storage, propylene fractionation, pipeline and NGL fractionation businesses.

 

W. Randall Fowler was elected Senior Vice President, Treasurer and a Director of our general partner in October 2006 and a Director of EPE Holdings and Enterprise Products GP in February 2006. Mr. Fowler was elected Senior Vice President and Treasurer of Enterprise Products GP in February 2005 and Chief Financial Officer of EPCO in April 2005. Mr. Fowler, a certified public accountant (inactive), joined Enterprise Products Partners as Director of Investor Relations in January 1999 and served as Treasurer and a Vice President of Enterprise Products GP and EPCO from August 2000 to February 2005. Mr. Fowler has served as Senior Vice President and Chief Financial Officer of EPE Holdings since August 2005.

 

Michael J. Knesek, a certified public accountant, was elected Senior Vice President, Principal Accounting Officer and Controller of our general partner in October 2006. He was also elected Senior Vice President and Principal Accounting Officer of Enterprise Products GP in February 2005. Previously, Mr. Knesek served as Principal Accounting Officer and a Vice President of Enterprise Products GP from August 2000 to February 2005. Mr. Knesek has served as Senior Vice President and Principal Accounting Officer of EPE Holdings since August 2005. Mr. Knesek has been the Controller and a Vice President of EPCO since 1990.

 

William A. Bruckmann, III, director, has been self-employed as a consultant and private investor since April 2004. From September 2002 to April 2004, Mr. Bruckmann served as a financial advisor with UBS Securities, Inc. He is a former managing director at Chase Securities, Inc. and has more than 25 years of banking experience, starting with Manufacturers Hanover Trust Company, where he became a senior officer in 1985. Mr. Bruckmann later served as managing director, sector head of the Manufacturers Hanover’s gas pipeline and midstream energy practices through the acquisition of Manufacturers Hanover by Chemical Bank and the acquisition of Chemical Bank by Chase Bank. Mr. Bruckmann also served as a director of Williams Energy Partners L.P. from May 2001 to June 2003. Mr. Bruckmann serves on our Audit, Conflicts and Governance Committee.

 

Larry J. Casey, director, has been a private investor managing real estate and personal investments since he retired in 1982 from a career in the energy industry. In 1974, Mr. Casey founded Xcel Products Company, a natural gas liquids and petrochemical trading company. Also in 1974, he founded Xral Underground Storage, the first privately-owned underground merchant storage facility for natural gas liquids and specialty chemicals at Mont Belvieu, Texas. Mr. Casey sold these companies in 1982. Mr. Casey serves on our Audit, Conflicts and Governance Committee.

 

Joe D. Havens, director, has been an entrepreneur engaged in the energy, banking and real estate industries. Mr. Havens founded Enterprise Petroleum Company, Inc., the predecessor to EPCO, in 1968, and sold his interest in the successor entity and related businesses to Mr. Duncan in 1990. Mr. Havens has also served on the board of directors of the First Commerce Bank of Corpus Christi, a private bank, since 1991, and currently serves as that board’s Chairman. Mr. Havens serves on our Audit, Conflicts and Governance Committee.

 

 

 

 

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Item 11. Executive Compensation.

 

We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, DEP GP, the executive officers of which are employees of EPCO. Our reimbursement for the compensation of executive officers is governed by the administrative services agreement with EPCO. For a description of the administrative services agreement, see “Relationship with EPCO” under Item 13 of this annual report. We have no compensation committee.

 

None of the named executive officers of our general partner were allocated compensation with respect to our specific operations during 2006 or 2005. Since the named executive officers of our general partner were allocated compensation with respect to Enterprise Products Partners (as a whole),and/or Enterprise GP Holdings, we cannot indicate historical salaries or other elements of compensation that could have been allocated or paid by EPCO and allocated to us pursuant to the administrative services agreement. Each of these named executive officers continues to perform services for Enterprise Products Partners and other affiliates.

 

Compensation Discussion and Analysis

 

During 2006, none of our executive officers had any of their time or compensation allocated specifically to our assets or businesses. Our chief executive officer (Mr. Bachmann), chief financial officer (Mr. Creel) and three other officers (Messrs. Radtke, Fowler and Knesek) constitute our most highly compensated executive officers at December 31, 2006 (collectively, the “named executive officers”). Our named executive officers will have substantially less than a majority of their time and compensation allocated to us, other than Mr. Radtke, who we expect may have a majority of his time allocated to us. With respect to our named executive officers, compensation paid or awarded by us in 2007 will reflect only that portion of each individual’s compensation paid by EPCO that is allocated to us pursuant to the administrative services agreement, including an allocation of a portion of the cost of equity-based long-term incentive plans of EPCO.

 

Dan L. Duncan controls EPCO and has ultimate decision-making authority with respect to the compensation of our named executive officers. The following elements of compensation, and EPCO’s decisions with respect to determinations of payments, are not subject to approvals by our Board or our ACG Committee. Equity-based awards under long-term incentive plans involving securities of Enterprise Products Partners or Enterprise GP Holdings are approved by the ACG Committee of their respective general partners. Our general partner, the general partner of Enterprise Products Partners and the general partner of Enterprise GP Holdings have no separate compensation committees.

 

As discussed in the following paragraphs, the elements of EPCO’s compensation program, along with EPCO’s other rewards (for example, benefits, work environment, career development), are intended to provide a total rewards package designed to drive performance and reward contributions in support of the business strategies of EPCO and its affiliates at the partnership and individual levels. During 2006, EPCO did not include any elements based on targeted performance-based criteria.

 

The primary elements of EPCO’s compensation program are a combination of annual cash and long-term equity-based incentive compensation. During 2006, the elements of compensation for our named executive officers consisted of the following:

 

 

 

 

 

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With respect to compensation objectives and decisions regarding our named executive officers during 2006, Mr. Duncan sought and received recommendations of Robert G. Phillips, the chief executive officer of Enterprise Products Partners, after preliminary formulation of such recommendation by him and the senior vice president of Human Resources for EPCO with respect to employees other than Mr. Phillips. EPCO takes note of market data for determining relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, various relevant compensation surveys. EPCO considered market data in a 2004-2005 survey prepared for EPCO by an outside compensation consultant, but did not otherwise consult with compensation consultants with respect to determining 2006 compensation for our named executive officers.

 

During late 2006, EPCO engaged an outside compensation consultant to prepare a report that it expects to consider when determining future compensation, but EPCO did not use this report with respect to decisions on discretionary annual cash compensation with respect to 2006 performance for any of our named executive officers. Mr. Duncan and EPCO do not use any formula or specific performance-based criteria for our named executive officers in connection with services performed for us, Enterprise Products Partners or their affiliates. All compensation determinations are discretionary and, as noted above, subject to Mr. Duncan’s ultimate decision-making authority. EPCO is expected to base the 2007 salaries of our named executive officers on the historical salaries paid to such individuals, market data and responsibilities of our named executive officers that may or may not be related to our business.

 

The discretionary cash awards paid to each of our named executive officers for work done on behalf of Enterprise Products Partners for the year ended December 31, 2006, were determined by consultation among Mr. Duncan, Mr. Phillips and the senior vice president of Human Resources for EPCO, and were subject to Mr. Duncan’s final determination. The cash awards, in combination with base salaries, are intended to yield competitive total cash compensation levels for the executive officers and drive performance in support of our business strategies, as well as the performance of Enterprise Products Partners and other EPCO affiliates for which our named executive officers perform services. The portion of any discretionary cash awards paid by EPCO allocable to us and reported as compensation to these executive officers are based on the administrative services agreement. It is EPCO’s general policy to pay these awards during the first quarter of each year.

 

The equity awards granted to our named executive officers in 2006 were determined by consultation among Mr. Duncan, Mr. Phillips and the senior vice president of Human Resources for EPCO, and were approved by the ACG Committee of the general partner of Enterprise Products Partners. These awards (restricted units and unit options) are intended to align the long-term interests of the executive officers of Enterprise Products Partners with those of its unitholders. It is EPCO’s general policy to recommend these grants to current employees during the second quarter of each fiscal year. Such awards were immaterial to the combined financial position, results of operation, and cash flows of Duncan Energy Partners Predecessor for all periods presented. See Note 2 of the Notes to Combined Financial Statements of Duncan Energy Partners Predecessor included under Item 8 of this annual report for additional information regarding our accounting for equity awards.

 

Each of our named executive officers are Class B limited partners of EPE Unit L.P. (the “Employee Partnership”). These limited partner interests (or “profits interests”) were awarded and issued during 2005 in connection with the initial public offering of Enterprise GP Holdings and provide additional long-term incentive compensation for our named executive officers. The profits interests awards entitle the holder to participate in the appreciation in value of Enterprise GP Holdings’ units since its initial public offering and are subject to forfeiture. The vesting date of these awards is December 5, 2011.

 

At December 31, 2006, our named executive officers held Class B limited partner interests in EPE Unit L.P. as follows: Richard H. Bachmann — 7.2%; Michael A. Creel — 7.2%; Gil H. Radtke — 2.4%; W. Randall Fowler — 4.8%; and Michael J. Knesek — 2.4%. Based on a closing market price of Enterprise GP Holdings’ units of $36.97 per unit at December 29, 2006 and taking into account the terms of liquidation outlined in the EPE Unit L.P. partnership agreement, we estimate that the total profits interest would have been worth $14.4 million, of which each named executive officer would have received his proportionate share. Since Enterprise GP Holdings has an indirect interest in us through its limited and

 

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general partner ownership interests in Enterprise Products Partners, our named executive officers may derive some benefit from these profits interests due to our results of operations. We, Enterprise Products Partners and Enterprise GP Holdings do not reimburse EPCO, the Employee Partnership or any of their affiliates or partners, through the administrative services agreement or otherwise, for any expenses related to the Employee Partnership.

 

EPCO generally does not pay for perquisites for any of our named executive officers, other than reimbursement of certain parking expenses, and expects to continue its policy of covering very limited perquisites allocable to our named executive officers. EPCO also makes matching contributions under its 401(k) plan for the benefit of our named executive officers in the same manner as for other EPCO employees.

 

EPCO does not offer our named executive officers a defined benefit pension plan. Also, none of our named executive officers had nonqualified deferred compensation during 2006.

 

We believe that each of the base salary, cash awards, and equity awards fit the overall compensation objectives of us, EPCO and Enterprise Products Partners, as stated above (i.e., to provide competitive compensation opportunities to align and drive employee performance toward the creation of sustained long-term unitholder value, which will also allow us to attract, motivate and retain high quality talent with the skills and competencies required by us).

 

Compensation of Directors of DEP GP

 

Neither we nor our general partner provide any additional compensation to employees of EPCO who serve as directors of our general partner. The employees of EPCO currently serving as directors are Messrs. Duncan, Bachmann, Creel, Radtke, and Fowler.

 

Cash Compensation. After our initial public offering, our independent directors are Messrs. Bruckmann, Casey and Havens. Our general partner is responsible for compensating these directors for their services. Its standard compensation arrangement is as follows:

 

 

 

Equity-Based Compensation. The independent directors of our general partner have been granted unit appreciation rights (“UARs”). These awards are in the form of letter agreements with each of the directors and are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings, Enterprise Products Partners or Duncan Energy Partners. The awards are based upon an incentive plan of EPE Holdings, and are made in the form of UAR grants for non-employee directors of our general partner (filed as an exhibit to this annual report on Form 10-K). The compensation expense associated with these awards is recognized by our general partner. These UARs entitle the directors to receive a cash amount in the future equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date price. If the director resigns prior to vesting, his UAR awards are forfeited.

 

On February 28, 2007, Messrs. Bruckmann, Casey and Havens were issued 30,000 UARs each under the letter agreement format. The grant date price of these rights was $36.68 per unit. These awards vest on February 28, 2012 or the date of certain qualifying events (as set forth in the form of grant). These awards are accounted for as liability awards under SFAS 123(R) by our general partner.

 

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

 

Security Ownership of Certain Beneficial Owners and Management

 

The following table sets forth certain information regarding the beneficial ownership of our common units as of March 31, 2007 by:

 

 

 

 

All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be. Each person has sole voting and dispositive power over the common units shown unless otherwise indicated below.

 

 

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

 

The following information summarizes our business relationships and related transactions with entities controlled by Dan L. Duncan during 2006. We have also provided information regarding our business relationships and transactions with our unconsolidated affiliate.

 

For additional information regarding our transactions with related parties, see Note 10 of the Notes to the Combined Financial Statements of Duncan Energy Partners Predecessor included under Item 8 of this annual report.

 

Historical relationship with Enterprise Products Partners

 

We participated in the Enterprise Products Partners’ cash management program for all periods presented. For purposes of presentation in our Statements of Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from us to Enterprise Products Partners equal to cash flows provided by operating activities less cash used in investing activities. Such transfers of excess cash are shown as distributions to owners in the Statements of Combined Owners’ Net Investment. As a result, the combined financial statements do not present cash balances for any of the periods presented.

 

Our related party revenues from Enterprise Products Partners include $59.0 million, $35.8 million and $21.7 million for the years ended December 31, 2006, 2005 and 2004, respectively, for the sale of natural gas. Our related party operating costs and expenses include the cost of sales for natural gas volumes Enterprise Products Partners sold to us. Such amounts were $20.3 million, $25.3 million and $3.8 million for the years ended December 31, 2006, 2005 and 2004, respectively.

 

In addition, Enterprise Products Partners furnished letters of credit on behalf of Evangeline’s debt service requirements. At December 31, 2006 and 2005, such outstanding letters of credit totaled $1.1 million and $1.2 million, respectively.

 

We also provide underground NGL and petrochemical storage services to Enterprise Products Partners. For the years ended December 31, 2006, 2005 and 2004, we recorded $20.1 million, $17.6 million and $17.0 million, respectively, in storage revenue for services provided to Enterprise Products Partners.

 

Enterprise Products Partners was the shipper of record on our Sabine Propylene and Lou-Tex Propylene Pipelines for each period presented. We recorded $39.1 million, $33.9 million and $40.9 million of related party revenues from Enterprise Products Partners in connection with these pipelines during the years ended December 31, 2006, 2005 and 2004, respectively. For the periods in which Sabine Propylene and Lou-Tex Propylene Pipelines were subject to FERC regulations, such related party revenues were based on the maximum tariff rate allowed for each system. We continued to charge Enterprise Products Partners such maximum transportation rates after both entities were declared exempt from FERC oversight.

 

Although Enterprise Products Partners was the shipper of record on the Sabine Propylene and Lou-Tex Propylene Pipelines, third parties were the actual users of these pipelines through exchange agreements each had with Enterprise Products Partners. Enterprise Products Partners recorded revenues of $15.5 million, $15.4 million and $14.2 million in connection with such agreements during the years ended December 31, 2006, 2005 and 2004, respectively. Apart from such third party exchange agreements, Enterprise Products Partners did not utilize these pipelines for its own transportation needs during the years ended December 31, 2006, 2005 and 2004.

 

Our ongoing relationship with Enterprise Products Partners

 

In connection with our initial public offering, certain commercial arrangements with Enterprise Products Partners went into effect. These arrangements include:

 

 

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Partnership will record revenues from these pipelines beginning in 2007 at exchange fees equal to those that Enterprise Products Partners would have recorded from such third parties. Although Enterprise Products Partners has assigned these agreements to the Partnership, it remains jointly and severally liable to the Partnership for performance of these agreements.

 

 

 

 

 

Omnibus Agreement. On February 5, 2007, Enterprise Products Partners entered into an Omnibus Agreement with the Partnership that will govern its relationship with the Partnership regarding the following matters:

 

 

 

 

 

Enterprise Products Partners has indemnified the Partnership against certain environmental and related liabilities arising out of or associated with the operation of the assets before February 5, 2007. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, the Partnership is not entitled to indemnification until

 

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the aggregate amount of claims exceeds $250 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the environmental indemnity.

 

 

 

 

Enterprise Products Partners has agreed to make additional contributions to the Partnership as reimbursement for the Partnership’s 66% share of any excess construction costs above (i) the $28.6 million of estimated capital expenditures to complete planned Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional planned brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas. The Partnership retained $30.6 million of the net proceeds from its initial public offering to fund its 66% share of post-February 5, 2007 estimated construction costs and liabilities. This retained amount consists of (i) $18.9 million for the Phase II expansion of the DEP South Texas NGL Pipeline System, (ii) $7.8 million for the brine-related expansion projects and (iii) $3.9 million for remaining liabilities associated with the initial construction phase of the DEP South Texas Pipeline System.

 

The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of our general partner, adversely affect holders of the Partnership’s common units.

 

Neither Enterprise Products Partners nor any of its affiliates are restricted under the Omnibus Agreement from competing with the Partnership. Except as otherwise expressly agreed in the EPCO administrative services agreement, Enterprise Products Partners and any of its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the administrative services agreement with Enterprise Products Partners, EPCO and other affiliates of EPCO.

 

Relationship with Evangeline

 

We sell natural gas to Evangeline, which, in turn, uses such natural gas to satisfy its sales commitments to Entergy. Our sales of natural gas to Evangeline totaled $277.7 million, $331.5 million and $241.4 million for the years ended December 31, 2006, 2005 and 2004, respectively.

 

Additionally, we have a service agreement with Evangeline whereby we provide Evangeline with construction, operations, maintenance and administrative support related to its pipeline system. Evangeline paid us $0.4 million, $0.4 million and $0.5 million for such services for the years ended December 31, 2006, 2005 and 2004, respectively.

 

Relationship with EPCO

 

We have no employees. All of our operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”). EPCO also provides general and administrative support services to us in accordance with the ASA. Enterprise Products Partners and the other affiliates of EPCO, including the Partnership, are parties to the ASA. The significant terms of the ASA are as follows:

 

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Likewise, our general and administrative costs include amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur 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, which in-turn is based on the estimated use of such services by each party (e.g., the allocation of general, legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). Our reimbursements to EPCO for general and administrative costs were $3.3 million, $3.9 million and $4.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

 

A small number of key employees of EPCO that devote a portion of their time to our operations and affairs also participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P. The amount of equity-based compensation allocable to the Partnership’s businesses was $72 thousand and $26 thousand for the years ended December 31, 2006 and 2005, respectively. Such amounts were immaterial to our combined financial position, results of operations and cash flows.

 

The ASA also addresses potential conflicts that may arise among Enterprise Products Partners and its general partner, the Partnership and its general partner, Enterprise GP Holdings L.P. and its general partner, and the EPCO Group, which includes EPCO and its other affiliates (but does not include the aforementioned entities and their controlled affiliates). The ASA provides, among other things, that:

 

 

 

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Enterprise GP Holdings will be presumed to desire to acquire the equity securities until such time as its general partner advises the EPCO Group, Enterprise Products GP and DEP GP that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the chief executive officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than such threshold amount, the chief executive officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.

 

In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, Enterprise Products GP and DEP GP, Enterprise Products Partners will have the second right to the pursue such acquisition either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of the Partnership.

 

In the event that Enterprise Products Partners affirmatively directs the opportunity to the Partnership, the Partnership may pursue such acquisition. Enterprise Products Partners will be presumed to desire to acquire the equity securities until such time as its general partner advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing Enterprise Products GP’s chief executive officer and ACG Committee.

 

In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to EPCO Holdings or TEPPCO and its general partner and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates.

 

 

In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the chief executive officer of Enterprise Products GP after consultation with and subject to the approval of the ACG Committee of Enterprise Products GP. If the purchase price or cost is reasonably likely to be less than such threshold amount, the chief executive officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s ACG Committee.

 

In the event that Enterprise Products Partners affirmatively directs the business opportunity to the Partnership, the Partnership may pursue such business opportunity. In the event that Enterprise Products Partners abandons the business opportunity for itself and the Partnership and so notifies

 

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the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity, and will be presumed to desire to do so, until such time as EPE Holdings shall have determined to abandon the pursuit of such opportunity in accordance with the procedures described above, and shall have advised the EPCO Group that Enterprise GP Holdings has abandoned the pursuit of such acquisition.

 

In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, the EPCO Group may either pursue the business opportunity or offer the business opportunity to EPCO Holdings or TEPPCO and its general partner and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.

 

None of the EPCO Group, Enterprise GP Holdings and its general partner, the Partnership and its general partner, or Enterprise Products Partners and its general partner have any obligation to present business opportunities to TEPPCO, TEPPCO GP or their controlled affiliates. Likewise, TEPPCO and its general partner and their controlled affiliates have no obligation to present business opportunities to the EPCO Group, Enterprise GP Holdings and its general partner, the Partnership and its general partner, or Enterprise Products Partners and its general partner.

 

On February 28, 2007, due to the substantial completion of inquires by the  Federal Trade Commission (“FTC”)  into EPCO’s acquisition of TEPPCO GP, the parties to the ASA amended it to remove Exhibit B thereto, which had been adopted to address matters the parties anticipated the FTC may consider in its inquiry.  Exhibit B had set forth certain separateness and screening policies and procedures among the parties that became unnecessary upon the issuance of the FTC's order in connection with the inquiry or were already otherwise reflected in applicable FTC, SEC, NYSE or other laws, standards or governmental regulations. 

 

Review and Approval of Transactions with Related Parties

 

Our partnership agreement and ACG Committee charter set forth policies and procedures for the review and approval of certain transactions with persons affiliated with or related to us. As further described below, our partnership agreement and ACG Committee charter set forth procedures by which related party transactions and conflicts of interest may be approved or resolved by our general partner or the ACG Committee. Under our partnership agreement, unless otherwise expressly provided therein or in the partnership agreement of EPOLP, whenever a potential conflict of interest exists or arises between our general partner or any of its affiliates, on the one hand, and us, any of our subsidiaries or any partner, on the other hand, any resolution or course of action by our general partner or its affiliates in respect of such conflict of interest is permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement, the partnership agreement of EPOLP or any agreement contemplated by such agreements, or of any duty stated or implied by law or equity, if the resolution or course of action is or, by operation of the partnership agreement is deemed to be, fair and reasonable to us; provided that, any conflict of interest and any resolution of such conflict of interest will be conclusively deemed fair and reasonable to us if such conflict of interest or resolution is (i) approved by a majority of the members of our ACG Committee (“Special Approval”), or (ii) on terms objectively demonstrable to be no less favorable to us than those generally being provided to or available from unrelated third parties.

 

The ACG Committee (in connection with Special Approval) is authorized in connection with its resolution of any conflict of interest to consider:

 

 

 

 

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Our general partner or its Board of Directors may, in their discretion, request that our ACG Committee review and approve related party transactions. The review and approval process of the ACG Committee, including factual matters that may be considered in determining whether a transaction is fair and reasonable, is generally governed by Section 7.9 of our partnership agreement. As discussed above, the ACG Committee’s Special Approval is conclusively deemed fair and reasonable to us under the partnership agreement. The processes followed by our management in approving or obtaining approval of related party transactions are in accordance with our written management authorization policy, which has been approved by the Board.

 

Under our Board-approved management authorization policy, the officers of our general partner have authorization limits for purchases and sales of assets, capital expenditures, commercial and financial transactions and legal agreements that ultimately limit the ability of executives of our general partner to enter into transactions involving capital expenditures in excess of $100 million without Board approval. This policy covers all transactions, including transactions with related parties. For example, under this policy, the chairman of our general partner may approve capital expenditures or the sale or other disposition of our assets up to a $100 million limit. Furthermore, any two of the chief executive officer and senior executives who are directors of our general partner may approve capital expenditures or the sale or other disposition of our assets up to a $100 million limit and individually may approve capital expenditures or the sale or other disposition of our assets up to $50 million. These senior executives have also been granted full approval authority for commercial, financial and service contracts.

 

In submitting a matter to the ACG Committee, the Board or the general partner may charge the committee with reviewing the transaction and providing the Board a recommendation, or it may delegate to the committee the power to approve the matter. When so engaged, the ACG Committee Charter currently provides that the ACG Committee may, if it deems necessary or advisable, perform the following functions:

 

 

 

 

 

In the normal course of business, our management routinely reviews all other related party transactions, including proposed asset purchases and business combinations and purchases and sales of product. As a matter of course, management reviews the terms and conditions of the proposed transactions, performs appropriate levels of due diligence and assesses the impact of the transaction on our partnership.

 

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The ACG Committee does not separately review transactions covered by our administrative services agreement with EPCO, which agreement has previously been approved by the ACG Committee and/or the Board. The administrative services agreement governs numerous day-to-day transactions between us and our subsidiaries and EPCO and its affiliates, including the provision by EPCO of administrative and other services to us and our subsidiaries and our reimbursement of costs for those services. For a description of the administrative services agreement, please read “Relationship with EPCO” within this Item 13.

 

The policies and procedures described above are applicable to related party transactions occurring after the effectiveness of our initial public offering, which we completed on February 5, 2007. The transactions between Duncan Energy Partners Predecessor and related parties referenced under this Item 13 occurred prior to the completion of our initial public offering and were therefore not governed by these policies and procedures.

 

Item 14. Principal Accountant Fees and Services.

 

We have engaged Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte & Touche”) as our principal accountant. The following table summarizes fees we have paid Deloitte & Touche for independent auditing, tax and related services for 2006 (dollars in thousands):

 

 

The ACG Committee of our general partner has approved the use of Deloitte & Touche as our independent principal accountant. In connection with its oversight responsibilities, the ACG Committee has adopted a pre-approval policy regarding any services proposed to be performed by Deloitte & Touche. The pre-approval policy includes four primary service categories: Audit, Audit-related, Tax and Other.

 

In general, as services are required, management and Deloitte & Touche submit a detailed proposal to the ACG Committee discussing the reasons for the request, the scope of work to be performed, and an estimate of the fee to be charged by Deloitte & Touche for such work. The ACG Committee discusses the request with management and Deloitte & Touche, and if the work is deemed necessary and

 

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appropriate for Deloitte & Touche to perform, approves the request subject to the fee amount presented (the initial “pre-approved” fee amount). As part of these discussions, the ACG Committee must determine whether or not the proposed services are permitted under the rules and regulations concerning auditor independence under the Sarbanes-Oxley Act of 2002 as well as rules of the American Institute of Certified Public Accountants. If at a later date, it appears that the initial pre-approved fee amount may be insufficient to complete the work, then management and Deloitte & Touche must present a request to the ACG Committee to increase the approved amount and the reasons for the increase.

 

Under the pre-approval policy, management cannot act upon its own to authorize expenditure for services outside of the pre-approved amounts. On a quarterly basis, the ACG Committee is provided a schedule showing Deloitte & Touche’s pre-approved amounts compared to actual fees billed for each of the primary service categories. The ACG Committee’s pre-approval process helps to ensure the independence of our principal accountant from management.

 

In order for Deloitte & Touche to maintain its independence, we are prohibited from using them to perform general bookkeeping, management or human resource functions, and any other service not permitted by the Public Company Accounting Oversight Board. The ACG Committee’s pre-approval policy also precludes Deloitte & Touche from performing any of these services for us.

 

PART IV

 

Item 15. Exhibits and Financial Statement Schedules.

 

(a)(1) Financial Statements

 

Our combined financial statements of Duncan Energy Partners Predecessor are included under Part II, Item 8 of this annual report. For a listing of these statements and accompanying footnotes, please see “Index to Financial Statements” under Item 8 of this annual report on Form 10-K.

 

(a)(2) Financial Statement Schedules

 

Schedule II – Valuation and Qualifying Accounts is included under Item 8 of this annual report on Form 10-K.

 

All schedules, except the one listed above, have been omitted because they are either not applicable, not required or the information called for therein appears in the combined financial statements or notes thereto.

 

(a)(3) Exhibits

 

 

 

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on April 2, 2007.

 

 

 

 

 

Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on April 2, 2007.

 

 

 

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Index to Exhibits

 

The following exhibits have been filed with this report. The other exhibits required to be filed with this annual report have been incorporated by reference as indicated in the exhibit table found under Item 15 of this annual report on Form 10-K.

 

 

 

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INDEX TO FINANCIAL STATEMENTS

 

 

 

 

 

 

 

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DUNCAN ENERGY PARTNER PREDECESSOR

REPORT OF INDEPENDENT REGISTERED ACCOUNTING FIRM

 

To the Board of Directors of

 Enterprise Products GP, LLC, general partner of Enterprise Products Partners L.P.

Houston, Texas

 

We have audited the accompanying combined balance sheets of Duncan Energy Partners Predecessor (the “Company”) as of December 31, 2006 and 2005, and the related statements of combined operations and comprehensive income, combined owners’ net investment, and combined cash flows for each of the three years in the period ended December 31, 2006. Our audits also include the financial statement schedule in Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of Duncan Energy Partners Predecessor at December 31, 2006 and 2005, and the combined results of its operations and its cash flows for the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic combined financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

 

The accompanying combined financial statements have been prepared from the separate records maintained by Enterprise Products Partners L.P. and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to Enterprise Products Partners L.P. or affiliates including EPCO, Inc.

 

/s/  Deloitte & Touche LLP

 

Houston, Texas

April 2, 2007

 

 

 

 

 

 

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DUNCAN ENERGY PARTNERS PREDECESSOR

COMBINED BALANCE SHEETS

(Dollars in thousands)

 

					December 31,
ASSETS					2006	2005
Current assets
	Accounts receivable – trade, net of allowance for doubtful accounts
	of $402 at December 31, 2006 and $3,372 at December 31, 2005				$    71,776	$  110,680
	Inventories				13,538	9,855
	Prepaid and other current assets				792	535
			Total current assets		86,106	121,070
Property, plant and equipment, net					707,649	512,197
Investments in and advances to unconsolidated affiliate					3,391	2,375
Intangible assets, net of accumulated amortization of $1,161 at
December 31, 2006 and $929 at December 31, 2005					6,966	7,198
			Total assets		$  804,112	$  642,840
LIABILITIES AND OWNERS’ NET INVESTMENT
Current liabilities
	Accounts payable – trade				$         702	$      1,171
	Accrued gas payables				62,571	101,475
	Accrued costs and expenses				5,093	967
	Deposits from customers				41	357
	Other current liabilities				9,222	10,495
			Total current liabilities		77,629	114,465
Other long-term liabilities					686	608
Commitments and contingencies
Owners’ net investment					725,797	527,767
			Total liabilities and owners’ net investment		$  804,112	$  642,840

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Combined Financial Statements

 

F-3

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DUNCAN ENERGY PARTNERS PREDECESSOR

STATEMENTS OF COMBINED OPERATIONS

AND COMPREHENSIVE INCOME

(Dollars in thousands)

 

	For Year Ended December 31,
	2006	2005	2004
Revenues
Related parties	$  395,977	$  418,829	$  321,011
Third parties	528,501	534,568	427,920
Total revenues (see Note 11)	924,478	953,397	748,931
Costs and expenses
Operating costs and expenses
Related parties	51,808	60,978	29,410
Third parties	815,252	848,066	656,134
Total operating costs and expenses	867,060	909,044	685,544
General and administrative costs
Related parties	3,283	3,937	4,228
Third parties	203	546	1,214
Total general and administrative costs	3,486	4,483	5,442
Total costs and expenses	870,546	913,527	690,986
Equity in income of unconsolidated affiliate	958	331	231
Operating income	54,890	40,201	58,176
Other income (expense), net	459	(532)	(52)
Income before provision for income taxes and changes in
accounting principles	55,349	39,669	58,124
Provision for income taxes	(21)	--	--
Income before changes in accounting principles	55,328	39,669	58,124
Cumulative effect of changes in accounting principles	9	(582)	--
Net income and comprehensive income	$    55,337	$    39,087	$    58,124

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Combined Financial Statements

 

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DUNCAN ENERGY PARTNERS PREDECESSOR

STATEMENTS OF COMBINED CASH FLOWS

(Dollars in thousands)

 

		For Year Ended December 31,
		2006	2005	2004
Operating Activities
Net income		$    55,337	$    39,087	$    58,124
Adjustments to reconcile net income to net cash flows
provided by operating activities:
	Depreciation, amortization and accretion in
operating costs and expenses		21,371	19,427	18,374
	Equity-based compensation	72	26	--
	Equity in income of unconsolidated affiliate	(958)	(331)	(231)
	Cumulative effect of change in accounting principle	(9)	582	--
	Loss (gain) on sale of assets	(25)	5	(7)
	Deferred income tax expense	21	--	--
	Changes in fair market value of financial instruments	(56)	52	5
	Effect of changes in operating accounts:
Accounts receivable		38,904	(42,610)	(17,612)
Inventories		(3,684)	(5,039)	(1,297)
Prepaid and other current assets		(11)	312	1,203
Accounts payable		(469)	1,049	(20)
Accrued gas payable		(38,903)	37,987	22,180
Accrued expenses		(8,325)	(5,230)	(1,077)
Deposits from customers		(316)	(4,283)	(1,193)
Other current liabilities		(1,856)	(459)	1,014
Other long-term liabilities		--	(7)	--
Net cash flows provided by operating activities		61,093	40,568	79,463
Investing Activities
Capital expenditures		(106,354)	(21,298)	(8,475)
Contributions in aid of construction costs		807	1,826	1,567
Proceeds from sale of assets		27	9	7
Advances to unconsolidated affiliate		(59)	(40)	(30)
Cash used in investing activities		(105,579)	(19,503)	(6,931)
Financing Activities
Net cash contributions from and distributions to owners		44,486	(21,065)	(72,532)
Cash received (used) in financing activities		44,486	(21,065)	(72,532)
Net Changes in Cash and Cash Equivalents		--	--	--
Cash and Cash Equivalents, January 1		--	--	--
Cash and Cash Equivalents, December 31		$            --	$            --	$            --

 

 

 

 

 

 

 

See Notes to Combined Financial Statements

 

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DUNCAN ENERGY PARTNERS PREDECESSOR

STATEMENTS OF COMBINED OWNERS’ NET INVESTMENT

(Dollars in thousands)

 

Balance at December 31, 2003	$    524,127
Net income	58,124
Net cash distributions to owners	(72,532)
Balance at December 31, 2004	509,719
Net income	39,087
Non-cash contribution from owners	26
Net cash distributions to owners	(21,065)
Balance at December 31, 2005	527,767
Net income	55,337
Non-cash contribution from owners (see Note 2)	98,207
Net cash received from owners	44,486
Balance at December 31, 2006	$    725,797

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Combined Financial Statements

 

F-6

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DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

 

 

Note 1.  Background and Basis of Financial Statement Presentation

 

Partnership Organization

 

Duncan Energy Partners L.P. (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” The Partnership was formed in September 2006 to acquire, own and operate a diversified portfolio of midstream energy assets. On February 5, 2007, the Partnership completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at a price of $21.00 per unit, which generated net proceeds to the Partnership of $291.3 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, the Partnership distributed $260.6 million of these net proceeds to Enterprise Products Operating L.P., along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units (after giving the effect to the redemption of 1,950,000 common units). See Note 15.

 

The Partnership is owned 98% by its limited partners and 2% by its general partner, DEP Holdings, LLC (“DEP GP”), which is a wholly owned subsidiary of Enterprise Products Operating L.P. DEP GP is responsible for managing all of the Partnership’s operations and activities. EPCO Inc. (“EPCO”) provides all employees and certain administrative services for the Partnership.

 

Since the Partnership did not own any assets prior to February 2007, the purpose of these financial statements is to present the historical combined financial position and results of operations, cash flows and changes in equity of the predecessor companies (collectively referred to as “Duncan Energy Partners Predecessor”). Unless the context requires otherwise, references to “we,” “us,” “our” or “the Company” are intended to mean and include the combined businesses and operations of Duncan Energy Partners Predecessor as discussed below – Predecessor Company.

 

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P. and its consolidated subsidiaries, including Enterprise Products Operating L.P. Enterprise Products Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange under the ticker symbol “EPD.”

 

References to “EPOLP” mean Enterprise Products Operating L.P. and its consolidated subsidiaries. EPOLP controls the Partnership’s general partner and is a significant owner of the Partnership’s common units.

 

References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., which owns the general partner of Enterprise Products Partners. Enterprise GP Holdings is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange under the ticker symbol “EPE.”

 

The Partnership, DEP GP, Enterprise Products Partners, EPOLP and Enterprise GP Holdings are affiliates under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO and its other affiliates.

 

Predecessor Company

 

Duncan Energy Partners Predecessor was engaged in the business of (i) receiving, storing and delivering natural gas liquids (“NGLs”) and petrochemical products, (ii) gathering, transporting, storing and marketing natural gas and (iii) transporting propylene. The principal business entities included in the historical combined financial statements of Duncan Energy Partners Predecessor are (on a 100% basis): (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a Delaware limited liability company;

 

 

F-7

 

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(ii) Acadian Gas, LLC (“Acadian Gas”), a Delaware limited liability company; (iii) Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), a Delaware limited partnership, including its general partner; (iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), a Delaware limited partnership, including its general partner; and (v) South Texas NGL Pipelines, LLC (“South Texas NGL”), a Delaware limited liability company. EPOLP contributed a 66% equity interest in each of these five entities to the Partnership on February 5, 2007. EPOLP retained the remaining equity interests.

 

The following is a brief description of the operations of each business comprising the Company:

 

§

Mont Belvieu Caverns owns and operates 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 million barrels, and a brine system with approximately 20 million barrels of above ground storage capacity and two brine production wells. Mont Belvieu Caverns receives, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast.

§

Acadian Gas gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of high-pressure transmission lines and lateral and gathering lines with an aggregate throughput capacity of one billion cubic feet per day including a 27-mile pipeline owned by its joint venture unconsolidated affiliate, Evangeline Gas Pipeline L.P., (“Evangeline”) and a leased storage cavern with three billion cubic feet of storage capacity (see Note 7).

 

§

Lou-Tex Propylene owns a 263-mile pipeline used to transport chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas.

 

§

Sabine Propylene owns a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana on a transport-or-pay basis.

 

§

South Texas NGL owns a 220-mile pipeline extending from Corpus Christi, Texas to Pasadena, Texas that was purchased by Enterprise Products Partners from a third-party in August 2006 for $97.7 million. Beginning in January 2007, this pipeline (along with others constructed and acquired since August 2006) commenced transportation of NGLs from two of Enterprise Products Partners’ processing facilities located in South Texas to Mont Belvieu, Texas. The total estimated cost to acquire and construct the additional pipelines that completed this system was $66.3 million (unaudited). Upon completion, this pipeline system will be called the DEP South Texas NGL Pipeline System.   Apart from Enterprise Products Partners’ acquisition of the pipeline from a third-party in August 2006 and the $19.6 million of subsequent expenditures through December 31, 2006 by South Texas NGL to modify this pipeline, the Company’s historical combined financial statements do not reflect any transactions related to this asset.

 

Enterprise Products Partners has owned controlling interests and operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years. Historically, EPOLP operated the assets of these entities; however, on February 5, 2007, DEP Operating Partnership, L.P. (the primary operating subsidiary of the Partnership) assumed these responsibilities.

 

Basis of Financial Statement Presentation

 

The accompanying combined financial statements and related notes of the Company have been prepared using Enterprise Products Partners’ separate historical accounting records related to the operations owned by Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL. These combined financial statements have been prepared using Enterprise Products Partners’ historical basis in each entity’s assets and liabilities 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 Company if it had been operated as an unaffiliated entity. Transactions between us and related parties such as Enterprise Products Partners and EPCO have been identified in the combined statements (see Note 10).

 

 

F-8

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We view the accompanying combined financial statements as the predecessor of the Partnership. We believe the combined historical financial statements of the Company are relevant for investors evaluating the Partnership.

 

Our combined financial statements reflect the accounts of subsidiaries in which we have a controlling interest, after the elimination of all significant intercompany accounts and transactions. In the opinion of management, all adjustments necessary for a fair presentation of the combined financial statements, in accordance with generally accepted accounting principles in the United States of America (referred to as “GAAP”), have been made.

 

The Company has operated within the Enterprise Products Partners cash management program for all periods presented. For purposes of presentation in the Statements of Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from the Company to Enterprise Products Partners equal to net cash flows provided by operating activities less cash used in investing activities. Such transfers of excess cash are shown as distributions to owners in the Statements of Combined Owners’ Net Investment. As a result, the combined financial statements do not present cash balances for any of the periods presented.

 

Because a single direct owner relationship did not exist among these combined entities, the net investment in these entities (the “Owners’ net investment”) is shown in lieu of parent or owners’ equity in the combined financial statements. Enterprise Products Partners indirectly owned all of the equity interests of our subsidiaries during the periods presented.

 

 

Note 2.  Summary of Significant Accounting Policies

 

Allowance for Doubtful Accounts

 

Our allowance for doubtful accounts balance is generally determined based on specific identification and estimates of future uncollectible accounts, as appropriate. Our procedure for recording an allowance for doubtful accounts is based on (i) our historical experience, (ii) the financial stability of our customers and (iii) the levels of credit granted to customers. 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 we have recorded sufficient reserves to cover potential losses. As applicable our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts. Our allowance for doubtful accounts was $0.4 million and $3.4 million at December 31, 2006 and 2005, respectively. The reduction in the allowance for doubtful accounts is due to final receipts and adjustments related to a customer involved in a bankruptcy proceeding.

 

Contingencies

 

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management and legal counsel evaluate such contingent liabilities, and such evaluations inherently involve an exercise in judgment. In assessing loss contingencies, our legal counsel evaluates the perceived merits of legal proceedings that are pending against us and unasserted claims that may result in proceedings, if any, as well as the perceived merits of the amount of relief sought or expected to be sought therein from each.

 

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability is accrued in our financial statements. If the assessment indicates that a potential 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, is disclosed.

 

 

F-9

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

 

Deferred Revenue

 

In our storage business, we occasionally bill customers in advance of the periods in which we provide storage services. We record such amounts as deferred revenue. We recognize these revenues ratably over the applicable service period. Our deferred revenue was $1.4 million and $0.3 million at December 31, 2006 and 2005, respectively.

 

Deposits from Customers

 

Natural gas customers that pose a credit risk are required to make a prepayment (i.e., a deposit) to us in connection with sales transactions. Deposits from customers were approximately $0.1 million and $0.4 million at December 31, 2006 and 2005, respectively.

 

Dollar Amounts

 

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

 

Earnings per Unit

 

We have not included earnings per unit data since the Company did not have any outstanding units.

 

Environmental Costs

 

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s estimate of the ultimate cost to remediate a site. Ongoing environmental compliance costs are charged to expense as incurred. Expenditures to mitigate or prevent future environmental contamination are capitalized. Our operations include activities that are subject to federal and state environmental regulations.

 

Expenses for environmental compliance and monitoring were $0.4 million, $0.3 million and $0.2 million during 2006, 2005 and 2004, respectively. Our reserve for environmental remediation projects totaled $0.4 million at December 31, 2006.

 

Equity-Based Compensation

 

As is commonly the case with publicly traded limited partnerships, we did not directly employ any of the persons responsible for the management and operations of our businesses. These functions were performed by employees of EPCO pursuant to an administrative services agreement under the direction of the general partner of Enterprise Products Partners (see Note 10).

 

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P., which is a private company affiliate of EPCO. Prior to January 1, 2006, EPCO accounted for these awards using the provisions of Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees.” On January 1, 2006, EPCO adopted Statement of Financial Accounting Standard (“SFAS”) 123(R), “Accounting for Stock-Based Compensation,” to account for its equity awards. Upon adoption of this accounting standard, we recognized a cumulative effect of change in accounting principle of $9 thousand (a benefit).

 

Such awards were immaterial to our combined financial position, results of operation, and cash flows for all periods presented. The amount of equity-based compensation allocable to the Company’s

 

 

F-10

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businesses was $72 thousand and $26 thousand for the years ended December 31, 2006 and 2005, respectively.

 

Estimates

 

Preparing our combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect 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 a given period. Our actual results could differ from these estimates.

 

Exit and Disposal Costs

 

Exit and disposal costs are charges associated with an exit activity not associated with a business combination or with a disposal activity covered by SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Examples of these costs include (i) termination benefits provided to current employees that are involuntarily terminated under the terms of a benefit arrangement that, in substance, is not an ongoing benefit arrangement or an individual deferred compensation contract, (ii) costs to terminate a contract that is not a capital lease, and (iii) costs to consolidate facilities or relocate employees. In accordance with SFAS 146, “Accounting for Costs Associated with Exit and Disposal Activities,” we recognize such costs when they are incurred rather than at the date of our commitment to an exit or disposal plan. We have not recognized any such costs for the periods presented.

 

Fair Value Information

 

Due to their short-term nature, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values. The fair values associated with our commodity financial instruments were developed using available market information and appropriate valuation techniques.

 

The following table presents the estimated fair values of our financial instruments at the dates indicated:

 

		December 31, 2006		December 31, 2005
		Carrying	Fair	Carrying	Fair
Financial Instruments		Value	Value	Value	Value
Financial assets:
	Accounts receivable	$    71,776	$    71,776	$  110,680	$  110,680
	Commodity financial instruments (1)	763	763	517	517
Financial liabilities:
	Accounts payable and accrued expenses	68,366	68,366	103,613	103,613
	Commodity financial instruments (1)	760	760	570	570
(1)   Represent commodity financial instrument transactions that have either (i) not settled or (ii) settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

 

Financial Instruments

 

We use financial instruments in connection with the operations of Acadian Gas, to secure certain fixed price natural gas sales contracts (referred to as “customer fixed-price arrangements”). Acadian Gas also enters into a limited number of cash flow hedges. We recognize such instruments on the balance sheet as assets or liabilities based on an instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met.

 

To qualify as a hedge, the item to be hedged must expose us to commodity price risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133,

 

 

F-11

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“Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We formally designate such financial instruments as hedges and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is immediately recognized in earnings. Our customer fixed-price arrangements do not qualify for hedge accounting under SFAS 133; therefore, these instruments are accounted for using a mark-to-market approach each reporting period.

 

If a financial instrument meets the criteria of a cash flow hedge, gains and losses from the instrument are recorded in other comprehensive income. Gains and losses on cash flow hedges are reclassified from other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the underlying asset. If the financial instrument meets the criteria of a fair value hedge, gains and losses from the instrument will be recorded on the income statement to offset corresponding losses and gains of the hedged item. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

 

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 whenever 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 in accordance with SFAS 144. 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 carrying value of a long-lived asset exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge is recognized equal to the excess of the asset’s carrying value over its estimated fair value. Fair value is defined as the estimated amount at which an asset or liability could be bought or settled, respectively, in an arm’s-length transaction. We measure fair value using market prices or, in the absence of such data, appropriate valuation techniques. We had no such impairment charges during the periods presented.

 

Impairment Testing for Unconsolidated Affiliate

 

We evaluate our equity method investment for impairment whenever events or changes in circumstances indicate that there is a potential loss in value of the investment (other than a temporary decline). Examples of such events or changes in circumstances include a history of investee operating losses or long-term adverse changes in the investee’s industry. If we determine that a loss in the investment’s value is attributable to an event other than temporary decline, we adjust the carrying value of the investment to its fair value through a charge to earnings. We had no such impairment charges during the periods presented.

 

Inventories

 

Our inventory consists of natural gas volumes valued at the lower of average cost or market. We capitalize as a cost of inventory shipping and handling charges directly related to volumes we purchase from third parties. As volumes are sold and delivered out of inventory, the average cost of these products is charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred.

 

At December 31, 2006 and 2005, the value of our natural gas inventory was $13.5 million and $9.9 million, respectively. As a result of fluctuating market conditions, we recognize lower of average cost or market (“LCM”) adjustments when the historical cost of our inventory exceeds its net realizable value. These non-cash adjustments are recorded as a component of operating costs and expenses. For the year ended December 31, 2006 and 2005, we recognized LCM adjustments of approximately $0.2 million and $3.2 million, respectively. No LCM adjustments were required during 2004.

 

 

 

F-12

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Investments in Unconsolidated Affiliate

 

We initially evaluate our ownership of financial interests in a business enterprise for consolidation consideration purposes related to variable interest entities. Then investment interests in which we own 3% to 50% and exercise significant influence over the investee’s operating and financial policies are accounted for using the equity method. If the investee is organized as a limited partnership or a limited liability company and maintains separate ownership accounts for its members, we account for our investment using the equity method if our ownership interest is between 3% and 50%. For all other types of investees, we apply the equity method of accounting if our ownership interest is between 20% and 50%. Our proportionate share of profits and losses from transactions with our equity method unconsolidated affiliate is eliminated in combination. If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

 

We include equity earnings from our unconsolidated affiliate, Evangeline, in our measure of segment gross operating margin and combined operating income due to the integrated nature of its operations with that of Acadian Gas. See Note 7 for information regarding our equity method investment.

 

Natural Gas Imbalances

 

Natural gas imbalances result when a customer injects more or less gas into a pipeline than it withdraws. Our imbalance receivables and payables are valued at market prices which represent cost. At December 31, 2006 and 2005, our imbalance receivables were $2.6 million and $1.6 million, respectively. Imbalance receivables are reflected as a component of “Accounts receivable — trade” on our Combined Balance Sheets. At December 31, 2006 and 2005, our imbalance payable was $0.5 million and $2.9 million respectively. Imbalance payable is reflected as a component of “Accrued gas payables” on our Combined Balance Sheets.

 

Owner’s net investment

 

In August 2006, Enterprise Products Partners purchased a pipeline for approximately $97.7 million in cash, and contributed this pipeline to South Texas NGL. This contribution is reflected as a non-cash contribution on the Statement of Combined Owners’ Net Investment.

 

Property, Plant and Equipment

 

Property, plant and equipment is recorded at cost. Expenditures for major additions and improvements are capitalized and minor replacements, maintenance, and repairs are charged to expense as incurred. We use the expense-as-incurred method for planned major maintenance activities.

 

When property and equipment are retired or otherwise disposed of, the cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. We record depreciation over the estimated useful lives of our assets primarily using the straight-line method for financial statement purposes. We use other depreciation methods (generally accelerated) for tax purposes where appropriate.

 

We account for asset retirement obligations (“AROs”) using SFAS 143, “Accounting for Asset Retirement Obligations,” as interpreted by FIN 47, “Accounting for Conditional Asset Retirement Obligations.” Asset retirement obligations are legal obligations associated with the retirement of a tangible long-lived asset that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the combined cost of the asset and the capitalized asset retirement obligation using a systematic and rational allocation method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO liability will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present

 

 

F-13

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value of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Upon settlement, our ARO obligations will be extinguished at either the recorded amount or we will incur a gain or loss on the difference between the recorded amount and the actual settlement cost.

 

See Note 6 for additional information regarding our property, plant and equipment and related AROs.

 

Provision for Income Taxes

 

Our entities are organized as pass-through entities for income tax purposes. As a result, the owners of such entities are responsible for federal income taxes on their share of each entity’s taxable income.

 

In May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced its franchise tax. In general, legal entities that conduct business in Texas are subject to the Texas Margin Tax. Limited partnerships, limited liability companies, corporations and limited liability partnerships are examples of the types of entities that are subject to the Texas Margin Tax. As a result of the change in tax law, our tax status in the State of Texas will change from non-taxable to taxable. We recorded a net deferred tax liability of $21 thousand due to the enactment of the Texas margin tax.  The offsetting net charge of $21 thousand is shown on our Statements of Combined Operations as a component of provision for income taxes for the year ended December 31, 2006.

 

Revenue Recognition

 

See Note 4 for information regarding our revenue recognition policies.

 

Start-Up and Organization Costs

 

Start-up costs and organization costs are expensed as incurred. Start-up costs are defined as one-time activities related to opening a new facility, introducing a new product or service, conducting activities in a new territory, pursuing a new class of customer, initiating a new process in an existing facility, or some new operation. Routine ongoing efforts to improve existing facilities, products or services are not start-up costs. Organization costs include legal fees, promotional costs and similar charges incurred in connection with the formation of a business. We did not record any such costs during the periods presented.

 

Storage Well and Operational Measurement Gains and Losses

 

Storage well measurement gains and losses occur when product movements into a storage well are different than those redelivered to customers. In general, such variations result from difficulties in precisely measuring significant volumes of liquids at varying flow rates and temperatures. It is expected that substantially all product delivered into a storage well will be withdrawn over time. As a result, a storage well measurement loss in one period is expected to be offset by a storage well measurement gain in a subsequent period, unless product is physically lost in a well due to problems with cavern integrity. We did not experience any cavern integrity events during the three years ended December 31, 2006.

 

Since we expect that storage well measurement gains and losses offset each other over time, we have historically charged storage well gains or losses to a storage imbalance reserve account during the month such imbalances occur based on current pricing. This reserve has been increased by the impact of measurement gains and decreased by measurement losses. On an annual basis, the storage imbalance reserve account has been reviewed for reasonableness based on historical storage well measurement gains and losses and adjusted accordingly through a charge to earnings. At December 31, 2006 and 2005, our storage imbalance reserve account was $4.0 million and $4.5 million, respectively. Net storage well measurement losses of $0.5 million, $2.0 million and $2.2 million were charged to the reserve during the years ended December 31, 2006, 2005 and 2004, respectively. Operating costs and expenses reflect storage well measurement loss accruals of $3.1 million and $0.6 million for the years ended December 31, 2005

 

 

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and 2004, respectively. We did not accrue for any storage well measurement losses for the year ended December 31, 2006.

 

Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. Many of our customer storage arrangements allow us to retain a small amount of product to help offset any operational measurement losses. These measurement variances are estimated and settled each reporting period at current prices as a net credit or charge to our operating costs and expenses. We do not own physical inventory volumes. We recorded net operational measurement gains of $0.2 million during each of the years ended December 31, 2006 and 2004. We recorded net operational measurement losses of $2.1 million during the year ended December 31, 2005.

 

Supplemental Cash Flow Information

 

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures based on activities initiated by the party. The majority of such arrangements are associated with projects related to pipeline construction and well tie-ins. We received $0.8 million, $1.8 million and $1.6 million as contributions in aid of our construction costs during the years ended December 31, 2006, 2005 and 2004, respectively.

 

Accounts payable related to our capital spending projects totaled $12.5 million and $4.8 million at December 31, 2006 and 2005, respectively.

 

 

Note 3. Recent Accounting Developments

 

The following information summarizes recently issued accounting guidance that will or may affect our future financial statements:

 

Emerging Issues Task Force Issue (“EITF”) No. 06-3

 

EITF 06-3, “How Taxes Collected From Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. This guidance specifically applies to taxes imposed by governmental authorities on revenue-producing transactions between sellers and customers (gross receipts taxes are excluded). We adopted EITF 06-3 on January 1, 2007. As a matter of policy, we have consistently reported such taxes on a net basis.

 

SFAS 155

 

SFAS 155, “Accounting for Certain Hybrid Financial Instruments,” amends SFAS 133, Accounting for Derivative Instruments and Hedging Activities, amends SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and resolves issues addressed in Statement 133 Implementation Issue D1, Application of Statement 133 to Beneficial Interests to Securitized Financial Assets. A hybrid financial instrument is one that embodies both an embedded derivative and a host contract. For certain hybrid financial instruments, SFAS 133 requires an embedded derivative instrument be separated from the host contract and accounted for as a separate derivative instrument. SFAS 155 amends SFAS 133 to provide a fair value measurement alternative for certain hybrid financial instruments that contain an embedded derivative that would otherwise be recognized as a derivative separately from the host contract. For hybrid financial instruments within its scope, SFAS 155 allows the holder of the instrument to make a one-time, irrevocable election to initially and subsequently measure the instrument in its entirety at fair value instead of separately accounting for the embedded derivative and host contract. This guidance was effective January 1, 2007, and our adoption of this guidance will have no impact on our financial position, results of operations or cash flows.

 

 

 

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SFAS 157

 

SFAS 157, “Fair Value Measurements,” defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required or permitted by other accounting standards and is expected to increase the consistency of those measurements. The statement emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop the measurements, and the effect of certain of the measurements on earnings (or changes in net assets) for the period. SFAS 157 is effective for fiscal years beginning after November 2007 and we will be required to adopt SFAS 157 on January 1, 2008. We do not believe that SFAS 157 will have a material impact on our financial position, results of operations, and cash flows since we already apply its basic concepts in measuring fair values used to record various transactions such as business combinations and asset acquisitions.

 

SFAS 159

 

SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115,” permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected would be reported in net income. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes the company elects for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact that the adoption of SFAS 159 will have on our financial statements.

 

Financial Accounting Standards Board Interpretation (“FIN”) No. 48

 

In accordance with FIN 48, “Accounting for Uncertainty in Income Taxes,” we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with a more than a 50% chance of being realized upon settlement. This guidance is effective January 1, 2007, and our adoption of this guidance is not anticipated to have a material impact on our financial position, results of operations or cash flows.

 

See Note 8 for new accounting principles adopted.

 

 

Note 4. Revenue Recognition

 

We recognize revenue using the following criteria: (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.

 

Our underground storage business generates revenues from contracts related to storage contract, storage capacity reservation agreements, throughput volumes and excess storage fees. With respect to capacity reservation agreements, we collect a fee for reserving space (typically in millions of barrels) for a customer’s product in our underground storage wells. Under these agreements, revenue is recognized ratably over the specified reservation period even if our customer does not utilize their reserved capacity. We also collect excess storage fees when customers exceed their reservation amounts. Such excess storage fees are recognized in the period of occurrence. Based on information currently available, we expect capacity reservation revenues of $26.9 million for 2007, $11.4 million for 2008, $9.3 million for 2009, $7.9 million for 2010 and $6.3 million for 2011. In addition, we derive brine production revenues from customers that use brine in the production of feedstocks for production of polyvinyl chloride (“PVC”).

 

 

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Our natural gas pipelines and services, and our petrochemical pipeline services generate revenues from transportation agreements where shippers are billed a fee per unit of volume transported (typically in million British thermal units for natural gas and thousand barrels per day for petrochemicals) multiplied by the volume delivered. The transportation fees charged under these arrangements are contractual. Revenues associated with these fee-based contracts are recognized when volumes have been physically delivered to our customer through the pipeline. All petrochemical pipeline revenues are with related parties (see Note 10).

 

Prior to 2004, Sabine Propylene was regulated by the Federal Energy Regulatory Commission (“FERC”). Lou-Tex Propylene was also subject to the FERC’s jurisdiction until 2005. The revenues recorded by Sabine Propylene and Lou-Tex Propylene during the period in which each entity was regulated were based on the maximum tariff rates approved by the FERC.

 

We also have natural gas sales contracts whereby revenue is recognized when we purchase and then resell and deliver a volume of natural gas to a customer. Revenues from these sales contracts are based upon market-related prices as determined by the individual agreements.

 

 

Note 5.  Financial Instruments

 

In addition to its natural gas transportation business, Acadian Gas engages in the purchase and sale of natural gas to third party customers in the Louisiana area. The price of natural gas fluctuates in response to changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. We may use commodity financial instruments such as futures, swaps and forward contracts to mitigate such risks. In general, the types of risks we attempt to hedge are those related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. The commodity financial instruments we utilize may be settled in cash or with another financial instrument. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

 

Acadian Gas enters into a small number of cash flow hedges in connection with its purchase of natural gas held-for-sale. In addition, Acadian Gas enters into a limited number of offsetting financial instruments that effectively fix the price of natural gas for certain of its customers. Historically, the use of commodity financial instruments by Acadian Gas was governed by policies established by the general partner of Enterprise Products Partners. The objective of this policy was to assist Acadian Gas in achieving its profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the general partner of Enterprise Products Partners. In general, Acadian Gas may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to its commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months.

 

The general partner of Enterprise Products Partners monitored the hedging strategies associated with the physical and financial risks of Acadian Gas (such as those mentioned previously), approved specific activities subject to the policy (including authorized products, instruments and markets) and established specific guidelines and procedures for implementing and ensuring compliance with the policy. The Partnership’s general partner will continue such policies in the future.

 

The fair value of our commodity financial instrument portfolio was a negligible amount at December 31, 2006 and a liability of $0.1 million at December 31, 2005. We recorded losses of $0.8 million and $0.2 million related to our commodity financial instruments for the years ended December 31, 2006 and 2005, respectively. In 2004, we recorded a gain of $0.2 million from our commodity financial instrument transactions.

 

 

 

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Note 6.  Property, Plant and Equipment

 

Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:

 

	Estimated Useful	At December 31,
	Life in Years	2006	2005
Natural gas and petrochemical pipelines
and related equipment (1)	5-35 (4)	$  350,360	$  343,843
Underground storage wells and related assets (2)	5-35 (5)	324,685	260,976
NGL pipelines and related equipment (6)	5-35	98,148	--
Transportation equipment (3)	3-10	1,240	1,102
Land		15,809	14,743
Construction in progress		61,839	15,063
Total		852,081	635,727
Less accumulated depreciation		144,432	123,530
Property, plant and equipment, net		$  707,649	$  512,197
(1)   Includes natural gas and petrochemical pipelines, office furniture and equipment, buildings, and related assets. (2)   Underground storage facilities include underground product storage caverns and related assets such as pipes and compressors. (3)   Transportation equipment includes vehicles and similar assets used in our operations. (4)   In general, the estimated useful life of major components of this category are: pipelines, 18-35 years (with some equipment at 5 years); office furniture and equipment, 3-20 years; and buildings 20-35 years. (5)   In general, the estimated useful life of underground storage facilities is 20-35 years (with some components at 5 years). (6)   Initial contribution from Enterprise Products Partners. In general, the estimated useful life of NGL pipelines will be 20-35 years (with some equipment at 5 years).

 

At December 31, 2006, construction in progress includes $19.6 million related to our investment in pipeline assets that will be part of the DEP South Texas NGL Pipeline System, which commenced operations in January 2007.

 

Depreciation expense for the years ended December 31, 2006, 2005 and 2004 was $21.4 million, $19.2 million and $18.1, respectively.

 

We have recorded conditional AROs in connection with certain right-of-way agreements, leases and regulatory requirements. Conditional AROs are obligations in which the timing and/or amount of settlement are uncertain. None of our assets are legally restricted for purposes of settling AROs. Our accrued liability for AROs was approximately $0.7 million and $0.6 million at December 31, 2006 and 2005, respectively. We recorded $0.1 million of accretion expense for the year ended December 31, 2006.

 

We recorded a cumulative effect of a change in accounting principle of $0.6 million in connection with our implementation of FIN 47 in December 2005, which represents the depreciation and accretion expense we would have recognized had we recorded these conditional AROs when incurred. Based on information currently available, we estimate that annual accretion expense will approximate $0.1 million for each of the years 2007 through 2011.

 

 

 

 

 

 

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Note 7.  Investments in and Advances to Unconsolidated Affiliate - Evangeline

 

Acadian Gas, through a wholly owned subsidiary, owns a collective 49.51% equity interest in Evangeline, which consists of a 45% direct ownership interest in Evangeline Gas Pipeline, L.P. (“EGP”) and a 45.05% direct interest in Evangeline Gas Corp. (“EGC”). EGC also owns a 10% direct interest in EGP. Third parties own the remaining equity interests in EGP and EGC. Acadian Gas does not have a controlling interest in the Evangeline entities, but does exercise significant influence on Evangeline’s operating policies. Acadian Gas accounts for its financial investment in Evangeline using the equity method since it is not the primary beneficiary of a variable interest entity.

 

At December 31, 2006 and 2005, the carrying value of our investment in Evangeline was $3.4 million and $2.4 million, respectively. Our Combined Statements of Operations and Comprehensive Income reflect equity earnings from Evangeline of $1.0 million, $0.3 million and $0.2 million for the years ended December 31, 2006, 2005 and 2004, respectively. Our investment in Evangeline is classified within our Natural Gas Pipelines & Services business segment.

 

Evangeline owns a 27-mile natural gas pipeline system extending from Taft, Louisiana to Westwego, Louisiana that connects three electric generation stations owned by Entergy Louisiana (“Entergy”). Evangeline’s most significant contract is a 21-year natural gas sales agreement with Entergy. Evangeline is obligated to make available-for-sale and deliver to Entergy certain specified minimum contract quantities of natural gas on an hourly, daily, monthly and annual basis. The sales contract provides for minimum annual quantities of 36.75 BBtus, until the contract expires on January 1, 2013. Quantities delivered to Entergy for the years ended December 31, 2006, 2005 and 2004 under the contract totaled 36.75 BBtus, 37.61 BBtus and 36.75 BBtus, respectively.

 

The sales contract contains provisions whereby Entergy is obligated to pay Evangeline a minimum fee each period, whether or not it is able to take delivery of natural gas volumes. The following table presents these minimum amounts for the annual periods presented:

 

2007	$    6,668
2008	6,638
2009	6,607
2010	6,578
2011	6,548
Thereafter	6,519
Total	$  39,558

 

In connection with the Entergy sales contract, Evangeline has entered into a natural gas purchase contract with Acadian Gas that contains annual purchase provisions. The minimum annual purchase quantities under this contract correspond to the aforementioned Entergy natural gas sales contract. The pricing terms of the sales agreement with Entergy and Evangeline’s purchase agreement with Acadian Gas are based on a weighted-average cost of natural gas each month (subject to certain market index price ceilings and incentive margins) plus a predetermined margin. Due to this pricing methodology, Evangeline’s monthly net sales margin under the Entergy gas sales contract is essentially fixed.

 

Entergy has the option to purchase the Evangeline pipeline system or an equity interest in Evangeline. In 1991, Evangeline entered into an agreement with Entergy whereby Entergy was granted the right to acquire Evangeline’s pipeline system for a nominal price, plus the complete performance and compliance with the natural gas sales contract. The option period begins the earlier of July 1, 2010 or upon the payment in full of Evangeline’s Series B notes as discussed below. It terminates on December 31, 2012. We cannot ascertain when, or if, Entergy will exercise this option. This uncertainty results from factors which include Entergy’s management decisions and regulatory approvals that may be required for Entergy to acquire Evangeline’s assets at the time the option is exercisable.

 

At December 31, 2006, long-term debt for Evangeline consisted of (i) $18.2 million in principal amount of 9.9% fixed interest rate senior secured notes due December 2010 (the “Series B” notes) and (ii) a

 

 

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$7.5 million subordinated note payable to an affiliate of the other co-venture participant (the “LL&E Note”). The Series B notes are collateralized by (i) Evangeline’s property, plant and equipment; (ii) proceeds from its Entergy natural gas sales contract; and (iii) a debt service reserve requirement. Scheduled principal repayments on the Series B notes are $5.0 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios. Evangeline was in compliance with such covenants during the periods presented.

 

Evangeline incurred the LL&E Note obligations in connection with its acquisition of the Entergy natural gas sales contract in 1991 and formation of the venture. The LL&E Note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at a LIBOR rate plus 0.5%. Variable interest rates charged on this note at December 31, 2006, 2005 and 2004 were 6.08%, 4.23% and 1.83%, respectively. At December 31, 2006, 2005 and 2004, the amount of accrued but unpaid interest on the LL&E Note is approximately $7.9 million, $7.1 million and $6.6 million, respectively.

 

Summarized financial information of Evangeline is presented below.

 

			At December 31
			2006	2005
BALANCE SHEET DATA:
	Current assets		$    30,510	$    35,918
	Property, plant and equipment, net		6,182	7,190
	Other assets		24,895	33,950
		Total assets	$    61,587	$    77,058
	Current liabilities		$    24,567	$    37,876
	Other liabilities		28,611	32,737
	Combined equity		8,409	6,445
		Total liabilities and combined equity	$    61,587	$    77,058
			For Year Ended December 31
			2006	2005	2004
INCOME STATEMENT DATA:
	Revenues		$  287,275	$  340,361	$  250,757
	Operating income		7,939	3,563	3,752
	Net income		1,964	526	231

 

 

Note 8. Cumulative Effect of Changes in Accounting Principles

 

During the years ended December 31, 2006 and 2005, we recorded amounts related to the cumulative effect of changes in accounting principles, including (i) a benefit of $9 thousand in January 2006 related to the implementation of SFAS 123(R) and (ii) a charge of $0.6 million in December 2005 related to our implementation of FIN 47.

 

SAB 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” addresses how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. This SAB requires us to quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The provisions of SAB 108 did not have a material impact on our combined financial statements.

 

 

 

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Effect of Implementation of SFAS 123(R)

 

SFAS 123(R) requires us to recognize compensation expense related to our equity awards based on the fair value of the award at the grant date. The fair value of an equity award is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an award is amortized to earnings on a straight-line basis over the requisite service or vesting period. Previously recognized deferred compensation related to restricted units was reversed on January 1, 2006.

 

Upon our adoption of SFAS 123(R), we recognized, as a benefit, a cumulative effect of a change in accounting principle of $9 thousand based on the SFAS 123(R) requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. See Note 2 for additional information regarding our accounting for equity awards.

 

Effect of Implementation of FIN 47

 

In December 2005, we adopted FIN 47, which required us to record a liability for AROs in which the timing and/or amount of settlement of the obligation is uncertain. These conditional asset retirement obligations were not addressed in SFAS 143, which we adopted on January 1, 2003. We recorded a charge of $0.6 million in connection with our implementation of FIN 47, which represents the depreciation and accretion expense we would have recognized in prior periods had we recorded these conditional asset retirement obligations when incurred. See Note 6.

 

 

Note 9.  Intangible Assets

 

At December 31, 2006 and 2005 our intangible assets consisted primarily of the value attributable to renewable storage contracts with various customers that we acquired in connection with the purchase of storage caverns from a third party in January 2002. We classify these intangible assets within our NGL & Petrochemical Storage Services business segment. Due to the renewable nature of the underlying contracts, we amortize our intangible assets on a straight-line basis over the estimated remaining economic life of the storage assets to which they relate.

 

The gross value of our intangible assets was $8.1 million at inception. At December 31, 2006 and 2005, the carrying value of these intangible assets was $7.0 million and $7.2 million, respectively. We recorded $0.2 million in amortization expense associated with these intangible assets for all periods presented. Based on information currently available, we estimate that amortization expense associated with existing intangible assets will approximate $0.2 million per year for each of the years 2007 through 2011.

 

 

 

 

 

 

 

 

 

 

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Note 10.  Related Party Transactions

 

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

 

		For Year Ended December 31
		2006	2005	2004
Revenues
	Enterprise Products Partners	$  118,237	$    87,307	$    79,611
	Evangeline	277,740	331,522	241,400
	Total	$  395,977	$  418,829	$  321,011
Operating costs and expenses
	EPCO	$    31,489	$    35,659	$    25,609
	Enterprise Products Partners	20,316	25,315	3,801
	Evangeline	3	4	--
	Total	$    51,808	$    60,978	$    29,410
General and administrative costs
	EPCO	$      3,283	$      3,937	$      4,228

 

The Company’s historical relationship with Enterprise Products Partners

 

We participated in the Enterprise Products Partners’ cash management program for all periods presented. For purposes of presentation in our Statements of Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from us to Enterprise Products Partners equal to cash flows provided by operating activities less cash used in investing activities. Such transfers of excess cash are shown as distributions to owners in the Statements of Combined Owners’ Net Investment. As a result, the combined financial statements do not present cash balances for any of the periods presented.

 

Our related party revenues from Enterprise Products Partners include $59.0 million, $35.8 million and $21.7 million for the years ended December 31, 2006, 2005 and 2004, respectively, for the sale of natural gas. Our related party operating costs and expenses include the cost of sales for natural gas volumes Enterprise Products Partners sold to us. Such amounts were $20.3 million, $25.3 million and $3.8 million for the years ended December 31, 2006, 2005 and 2004, respectively.

 

In addition, Enterprise Products Partners furnished letters of credit on behalf of Evangeline’s debt service requirements. At December 31, 2006 and 2005, such outstanding letters of credit totaled $1.1 million and $1.2 million, respectively.

 

We also provide underground NGL and petrochemical storage services to Enterprise Products Partners. For the years ended December 31, 2006, 2005 and 2004, we recorded $20.1 million, $17.6 million and $17.0 million, respectively, in storage revenue for services provided to Enterprise Products Partners.

 

Enterprise Products Partners was the shipper of record on our Sabine Propylene and Lou-Tex Propylene Pipelines for each period presented. We recorded $39.1 million, $33.9 million and $40.9 million of related party revenues from Enterprise Products Partners in connection with these pipelines during the years ended December 31, 2006, 2005 and 2004, respectively. For the periods in which Sabine Propylene and Lou-Tex Propylene were subject to FERC regulations (see Note 4), such related party revenues were based on the maximum tariff rate allowed for each system. We continued to charge Enterprise Products Partners such maximum transportation rates after both entities were declared exempt from FERC oversight.

 

Although Enterprise Products Partners was the shipper of record on the Sabine Propylene and Lou-Tex Propylene Pipelines, third parties were the actual users of these pipelines through exchange agreements each party had with Enterprise Products Partners. Enterprise Products Partners recorded revenues of $15.5 million, $15.4 million and $14.2 million in connection with such agreements during the years ended December 31, 2006, 2005 and 2004, respectively. Apart from such third party exchange

 

 

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agreements, Enterprise Products Partners did not utilize these pipelines for its own transportation needs during the years ended December 31, 2006, 2005 and 2004.

 

The Partnership’s ongoing relationship with Enterprise Products Partners

 

In connection with the Partnership’s initial public offering, certain commercial arrangements with Enterprise Products Partners went into effect. These arrangements include:

 

§

The assignment by Enterprise Products Partners of its third party product exchange agreements for use of the Sabine Propylene and Lou-Tex Propylene Pipelines to the Partnership. As a result, the Partnership will record revenues from these pipelines beginning in 2007 at exchange fees equal to those that Enterprise Products Partners would have recorded from such third parties. Although Enterprise Products Partners has assigned these agreements to the Partnership, it remains jointly and severally liable to the Partnership for performance of these agreements.

 

§

Mont Belvieu Caverns entered into several storage agreements with Enterprise Products Partners. The initial terms of these agreements commenced February 1, 2007 and end on December 31, 2016. These agreements include rates comparable to the rates Mont Belvieu Caverns charges third parties for storage contracts of similar size and duration. Mont Belvieu Caverns provides underground storage services to Enterprise Products Partners for several lines of its businesses, including NGL marketing, butane isomerization, octane enhancement, propylene fractionation and NGL fractionation.

 

§

An affiliate of Enterprise Products Partners assigned a ground lease to Mont Belvieu Caverns. Under this ground lease, Enterprise Products Partners, as lessee, is required to pay a monthly rental fee to Mont Belvieu Caverns, as lessor. The initial term of this ground lease commenced on January 17, 2002 and continues until the earlier to occur of (i) December 31, 2100 or (ii) termination by the lessee, for any reason, of its operations on the leased premises as permitted under the ground lease.

 

§

All storage well measurement gains and losses relating to Mont Belvieu Caverns’ underground storage activities are now retained by Enterprise Products Partners. In addition, Mont Belvieu Caverns makes a special allocation to Enterprise Products Partners of operational measurement gains and losses related to its storage services. See Note 2 for additional information regarding our historical storage well and operational measurement gains and losses.

 

§

South Texas NGL entered into a ten-year contract with Enterprise Products Partners for the transportation of NGLs from south Texas to Mont Belvieu, Texas. Under this contract, Enterprise Products Partners pays us a dedication fee of no less than $0.02 per gallon for all NGLs it produces at its Shoup and Armstrong NGL fractionation plants, whether or not any volumes are actually shipped on the pipelines owned by South Texas NGL. South Texas NGL does not take title to products transported on its pipeline system. Enterprise Products Partners will retain title and associated commodity risk.

 

Omnibus Agreement. On February 5, 2007, Enterprise Products Partners entered into an Omnibus Agreement with the Partnership that will govern its relationship with the Partnership regarding the following matters:

 

§

indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;

 

§

reimbursement of certain expenditures for South Texas NGL and Mont Belvieu Caverns;

 

§

a right of first refusal to Enterprise Products Partners in the Partnership’s current and future subsidiaries and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and

 

 

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§

a preemptive right with respect to equity securities issued by certain of the Partnership’s subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.

 

Enterprise Products Partners has indemnified the Partnership against certain environmental and related liabilities arising out of or associated with the operation of the assets before February 5, 2007. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, the Partnership is not entitled to indemnification until the aggregate amount of claims exceeds $250 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the environmental indemnity.

 

Enterprise Products Partners has also indemnified the Partnership for liabilities related to:

 

§

certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to the Partnership in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct the Partnership’s business that arise through February 5, 2010; and

 

§

certain income tax liabilities attributable to the operation of the assets contributed to the Partnership in connection with its initial public offering prior to February 5, 2007.

 

Enterprise Products Partners has agreed to make additional contributions to the Partnership as reimbursement for the Partnership’s 66% share of excess construction costs, if any, above (i) the $28.6 million of estimated capital expenditures to complete planned Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional planned brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas. The Partnership retained $30.6 million of the net proceeds from its initial public offering to fund its 66% share of post-February 5, 2007 estimated construction costs and liabilities. This retained amount consists of (i) $18.9 million for the Phase II expansion of the DEP South Texas NGL Pipeline System, (ii) $7.8 million for the brine-related expansion projects and (iii) $3.9 million for remaining liabilities associated with the initial construction phase of the DEP South Texas Pipeline System.

 

The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of our general partner, adversely affect holders of the Partnership’s common units.

 

Neither Enterprise Products Partners nor any of its affiliates are restricted under the Omnibus Agreement from competing with the Partnership. Except as otherwise expressly agreed in the EPCO administrative services agreement, Enterprise Products Partners and any of its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the administrative services agreement with Enterprise Products Partners, EPCO and other affiliates of EPCO.

 

Relationship with Evangeline

 

We sell natural gas to Evangeline, which, in turn, uses such natural gas to satisfy its sales commitments to Entergy. Our sales of natural gas to Evangeline totaled $277.7 million, $331.5 million and $241.4 million for the years ended December 31, 2006, 2005 and 2004, respectively.

 

Additionally, we have a service agreement with Evangeline whereby we provide Evangeline with construction, operations, maintenance and administrative support related to its pipeline system. Evangeline paid us $0.4 million, $0.4 million and $0.5 million for such services for the years ended December 31, 2006, 2005 and 2004, respectively.

 

 

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Relationship with EPCO

 

We have no employees. All of our operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”). EPCO also provides general and administrative support services to us in accordance with the ASA. Enterprise Products Partners and the other affiliates of EPCO, including the Partnership, are parties to the ASA. The significant terms of the ASA are as follows:

 

§

EPCO provides administrative, management, engineering and operating services as may be necessary to manage and operate our businesses, properties and assets (in accordance with prudent industry practices). EPCO employs or otherwise retains the services of such personnel as may be necessary to provide such services.

 

§

We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including EPCO expenses reasonably allocated to us). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, which may be applicable with respect to services provided by EPCO.

 

§

EPCO allows us to participate as named insureds in its overall insurance program with the associated premiums and related costs being allocated to us. We reimbursed EPCO $1.4 million, $1.7 million and $2.3 million for insurance costs for the years ended December 31, 2006, 2005 and 2004, respectively.

 

§

Our operating costs and expenses for the years ended December 31, 2006, 2005 and 2004 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including the compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Our reimbursements to EPCO for operating costs and expenses were $31.5 million, $35.7 million and $25.6 million for the years ended December 31, 2006, 2005 and 2004, respectively.

 

Likewise, our general and administrative costs include amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur 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, which in-turn is based on the estimated use of such services by each party (e.g., the allocation of general, legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). Our reimbursements to EPCO for general and administrative costs were $3.3 million, $3.9 million and $4.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

 

A small number of key employees of EPCO that devote a portion of their time to our operations and affairs also participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P. The amount of equity-based compensation allocable to the Company’s businesses was $72 thousand and $26 thousand for the years ended December 31, 2006 and 2005, respectively. Such amounts were immaterial to our combined financial position, results of operations and cash flows.

 

The ASA also addresses potential conflicts that may arise among Enterprise Products Partners and its general partner, the Partnership and its general partner, Enterprise GP Holdings L.P. and its general partner, and the EPCO Group, which includes EPCO and its other affiliates (but does not include the aforementioned entities and their controlled affiliates). The ASA provides, among other things, that:

 

§

If a business opportunity to acquire “equity securities” (as defined) is presented to the EPCO Group, Enterprise Products Partners and its general partner, the Partnership and its general partner, or Enterprise GP Holdings and its general partner, then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include:

 

 

F-25

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§

general partner interests (or securities which have characteristics similar to general partner interests) and incentive distribution rights or similar rights in publicly traded partnerships or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and

 

§

incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.

 

Enterprise GP Holdings will be presumed to desire to acquire the equity securities until such time as its general partner advises the EPCO Group, Enterprise Products GP and DEP GP that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the chief executive officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than such threshold amount, the chief executive officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.

 

In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, Enterprise Products GP and DEP GP, Enterprise Products Partners will have the second right to the pursue such acquisition either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of the Partnership.

 

In the event that Enterprise Products Partners affirmatively directs the opportunity to the Partnership, the Partnership may pursue such acquisition. Enterprise Products Partners will be presumed to desire to acquire the equity securities until such time as its general partner advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing Enterprise Products GP’s chief executive officer and ACG Committee.

 

In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to EPCO Holdings or TEPPCO and its general partner and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates.

 

§

If any business opportunity not covered by the preceding bullet point (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise GP Holdings and its general partner, the Partnership and its general partner, or Enterprise Products Partners and its general partner, Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of the Partnership. Enterprise Products Partners will be presumed to desire to pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the pursuit of such business opportunity.

 

In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the chief executive officer of Enterprise Products GP after consultation with and subject to the approval of the ACG Committee of Enterprise Products GP. If the purchase price or cost is

 

 

 

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reasonably likely to be less than such threshold amount, the chief executive officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s ACG Committee.

 

In the event that Enterprise Products Partners affirmatively directs the business opportunity to the Partnership, the Partnership may pursue such business opportunity. In the event that Enterprise Products Partners abandons the business opportunity for itself and the Partnership and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity, and will be presumed to desire to do so, until such time as EPE Holdings shall have determined to abandon the pursuit of such opportunity in accordance with the procedures described above, and shall have advised the EPCO Group that Enterprise GP Holdings has abandoned the pursuit of such acquisition.

 

In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, the EPCO Group may either pursue the business opportunity or offer the business opportunity to EPCO Holdings or TEPPCO and its general partner and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.

 

None of the EPCO Group, Enterprise GP Holdings and its general partner, the Partnership and its general partner, or Enterprise Products Partners and its general partner have any obligation to present business opportunities to TEPPCO, TEPPCO GP or their controlled affiliates. Likewise, TEPPCO and its general partner and their controlled affiliates have no obligation to present business opportunities to the EPCO Group, Enterprise GP Holdings and its general partner, the Partnership and its general partner, or Enterprise Products Partners and its general partner.

 

On February 28, 2007, due to the substantial completion of inquires by the  Federal Trade Commission (“FTC”)  into EPCO’s acquisition of TEPPCO GP, the parties to the ASA amended it to remove Exhibit B thereto, which had been adopted to address matters the parties anticipated the FTC may consider in its inquiry.  Exhibit B had set forth certain separateness and screening policies and procedures among the parties that became unnecessary upon the issuance of the FTC's order in connection with the inquiry or were already otherwise reflected in applicable FTC, SEC, NYSE or other laws, standards or governmental regulations. 

 

Review and Approval of Transactions with Related Parties

 

Our partnership agreement and ACG Committee charter set forth policies and procedures for the review and approval of certain transactions with persons affiliated with or related to us. As further described below, our partnership agreement and ACG Committee charter set forth procedures by which related party transactions and conflicts of interest may be approved or resolved by our general partner or the ACG Committee. Under our partnership agreement, unless otherwise expressly provided therein or in the partnership agreement of EPOLP, whenever a potential conflict of interest exists or arises between our general partner or any of its affiliates, on the one hand, and us, any of our subsidiaries or any partner, on the other hand, any resolution or course of action by our general partner or its affiliates in respect of such conflict of interest is permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement, the partnership agreement of EPOLP or any agreement contemplated by such agreements, or of any duty stated or implied by law or equity, if the resolution or course of action is or, by operation of the partnership agreement is deemed to be, fair and reasonable to us; provided that, any conflict of interest and any resolution of such conflict of interest will be conclusively deemed fair and reasonable to us if such conflict of interest or resolution is (i) approved by a majority of the members of our ACG Committee (“Special Approval”), or (ii) on terms objectively demonstrable to be no less favorable to us than those generally being provided to or available from unrelated third parties.

 

The ACG Committee (in connection with Special Approval) is authorized in connection with its resolution of any conflict of interest to consider:

 

 

 

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§

the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

 

§

the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership);

 

§

any customary or accepted industry practices and any customary or historical dealings with a particular person;

 

§

any applicable generally accepted accounting or engineering practices or principles;

 

§

the relative cost of capital of the parties and the consequent rates of return to the equity holders of the parties; and

 

§

such additional factors as the committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

 

Our general partner or its Board of Directors may, in their discretion, request that our ACG Committee review and approve related party transactions. The review and approval process of the ACG Committee, including factual matters that may be considered in determining whether a transaction is fair and reasonable, is generally governed by Section 7.9 of our partnership agreement. As discussed above, the ACG Committee’s Special Approval is conclusively deemed fair and reasonable to us under the partnership agreement. The processes followed by our management in approving or obtaining approval of related party transactions are in accordance with our written management authorization policy, which has been approved by the Board.

 

Under our Board-approved management authorization policy, the officers of our general partner have authorization limits for purchases and sales of assets, capital expenditures, commercial and financial transactions and legal agreements that ultimately limit the ability of executives of our general partner to enter into transactions involving capital expenditures in excess of $100 million without Board approval. This policy covers all transactions, including transactions with related parties. For example, under this policy, the chairman of our general partner may approve capital expenditures or the sale or other disposition of our assets up to a $100 million limit. Furthermore, any two of the chief executive officer and senior executives who are directors of our general partner may approve capital expenditures or the sale or other disposition of our assets up to a $100 million limit and individually may approve capital expenditures or the sale or other disposition of our assets up to $50 million. These senior executives have also been granted full approval authority for commercial, financial and service contracts.

 

In submitting a matter to the ACG Committee, the Board or the general partner may charge the committee with reviewing the transaction and providing the Board a recommendation, or it may delegate to the committee the power to approve the matter. When so engaged, the ACG Committee Charter currently provides that the ACG Committee may, if it deems necessary or advisable, perform the following functions:

 

§

Review a summary of the proposed transaction(s) that outlines (i) its terms and conditions (explicit and implicit), (ii) a brief history of the transaction, and (iii) the impact that the transaction will have on our unitholders and personnel, including earnings per unit and distributable cash flow.

 

§

Review due diligence findings by management and make additional due diligence requests, if necessary.

 

§

Engage third-party independent advisors, where necessary, to provide committee members with comparable market values, legal advice and similar services directly related to the proposed transaction.

 

 

 

F-28

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§

Conduct interviews regarding the proposed transaction with the most knowledgeable company officials to ensure that the committee members have all relevant facts before rendering their judgment.

 

In the normal course of business, our management routinely reviews all other related party transactions, including proposed asset purchases and business combinations and purchases and sales of product. As a matter of course, management reviews the terms and conditions of the proposed transactions, performs appropriate levels of due diligence and assesses the impact of the transaction on our partnership.

 

The ACG Committee does not separately review transactions covered by our administrative services agreement with EPCO, which agreement has previously been approved by the ACG Committee and/or the Board. The administrative services agreement governs numerous day-to-day transactions between us and our subsidiaries and EPCO and its affiliates, including the provision by EPCO of administrative and other services to us and our subsidiaries and our reimbursement of costs for those services. For a description of the administrative services agreement, please read “Relationship with EPCO” within this Note 10.

 

The policies and procedures described above are applicable to related party transactions occurring after the effectiveness of our initial public offering, which we completed on February 5, 2007. The transactions between Duncan Energy Partners Predecessor and related parties referenced under this Note 10 occurred prior to the completion of our initial public offering and were therefore not governed by these policies and procedures.

 

 

Note 11.  Business Segments

 

We classified our midstream energy operations into three reportable business segments: NGL & Petrochemical Storage Services, Natural Gas Pipelines & Services and Petrochemical Pipeline Services. NGL Pipeline Services will be reflected as our fourth business segment to encompass our South Texas NGL pipeline business, which became operational in January 2007. Our business segments are generally organized and managed according to the type of services rendered (or technology employed) and products produced and/or sold.

 

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

 

We define total (or combined) segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) gains and losses on the sale of assets; and (iii) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of any intersegment and intrasegment transactions. Our combined revenues reflect the elimination of all material intercompany transactions.

 

We include equity earnings from Evangeline in our measurement of segment gross operating margin and operating income. Our equity investments in midstream energy operations such as those conducted by Evangeline are a vital component of our long-term business strategy and important to the operations of Acadian Gas. This method of operation enables us to achieve favorable economies of scale relative to our level of investment and also lowers our exposure to business risks compared to the profile

 

 

 

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we would have on a stand-alone basis. Our equity investee is within the same industry as our combined operations, thus we believe treatment of earnings from our equity method investee as a component of gross operating margin and operating income is appropriate.

 

Our combined revenues were earned in the United States. Our underground storage wells in southeast Texas receive, store and deliver NGLs and petrochemical products for refinery and other customers along the upper Texas Gulf Coast. Acadian Gas gathers, transports, stores and markets natural gas to customers primarily in Louisiana. Our petrochemical pipelines provide propylene transportation services to shippers in southeast Texas and southwestern Louisiana. Beginning in January 2007, our DEP South Texas NGL Pipeline System transports NGLs from south Texas to Mont Belvieu, Texas for Enterprise Products Partners.

 

Combined property, plant and equipment and investments in and advances to our unconsolidated affiliate are allocated to each segment based on the primary operations of each asset or investment. The principal reconciling item between combined property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net carrying value of assets that contribute to the gross operating margin of a particular segment. Since assets under construction generally do not contribute to segment gross operating margin until completed, such assets are excluded from segment asset totals until they are deemed operational.

 

The following table shows our measurement of total segment gross operating margin for the periods indicated:

 

		Year Ended December 31,
		2006	2005	2004
Revenues (1)		$    924,478	$    953,397	$    748,931
Less:	Operating costs and expenses (1)	(867,060)	(909,044)	(685,544)
Add:	Equity in income of unconsolidated affiliate (1)	958	331	231
	Depreciation, amortization and accretion in operating costs and expenses (2)	21,443	19,453	18,374
	Gain (loss) on sale of assets in operating costs and expenses (2)	(25)	5	(7)
Total segment gross operating margin		$      79,794	$      64,142	$      81,985
(1)    These amounts are taken from our Statements of Combined Operations and Comprehensive Income. (2)    These non-cash expenses are taken from the operating activities section of our Statements of Combined Cash Flows.

 

 

A reconciliation of total segment gross operating margin to operating income and income before the cumulative effect of changes in accounting principles follows:

 

		Year Ended December 31,
		2006	2005	2004
Total segment gross operating margin		$    79,794	$    64,142	$    81,985
Adjustments to reconcile total segment gross operating margin
	to operating income:
	Depreciation, amortization and accretion in operating costs and expenses	(21,443)	(19,453)	(18,374)
	Gain (loss) on sale of assets in operating costs and expenses	25	(5)	7
	General and administrative costs	(3,486)	(4,483)	(5,442)
Combined operating income		54,890	40,201	58,176
	Other (income) expense, net	459	(532)	(52)
Income before cumulative effect of changes in accounting principles		$    55,349	$    39,669	$    58,124

 

 

 

 

 

 

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Information by segment, together with reconciliations to our combined totals, is presented in the following table:

 

			NGL and	Onshore
			Petrochemical	Natural Gas	Petrochemical	Adjustments
			Storage	Pipelines	Pipeline	and	Combined
			Services	& Services	Services	Eliminations	Totals
Revenues from third parties:
		Year ended December 31, 2006	$    39,031	$  489,470	$            --	$            --	$  528,501
		Year ended December 31, 2005	35,237	499,331	--	--	534,568
		Year ended December 31, 2004	32,555	395,365	--	--	427,920
Revenues from related parties:
		Year ended December 31, 2006	20,113	336,777	39,087	--	395,977
		Year ended December 31, 2005	17,601	367,362	33,866	--	418,829
		Year ended December 31, 2004	16,979	263,057	40,975	--	321,011
Total revenues:
		Year ended December 31, 2006	59,144	826,247	39,087	--	924,478
		Year ended December 31, 2005	52,838	866,693	33,866	--	953,397
		Year ended December 31, 2004	49,534	658,422	40,975	--	748,931
Equity in income of
	unconsolidated affiliate:
		Year ended December 31, 2006	--	958	--	--	958
		Year ended December 31, 2005	--	331	--	--	331
		Year ended December 31, 2004	--	231	--	--	231
Gross operating margin by individual
	business segment and in total:
		Year ended December 31, 2006	23,940	20,144	35,710	--	79,794
		Year ended December 31, 2005	16,636	18,939	28,567	--	64,142
		Year ended December 31, 2004	19,843	25,256	36,886	--	81,985
Segment assets:
		At December 31, 2006	246,068	209,550	92,044	159,987	707,649
		At December 31, 2005	191,757	211,045	94,332	15,063	512,197
Investments in and advances to
	unconsolidated affiliate (see Note 7):
		At December 31, 2006	--	3,391	--	--	3,391
		At December 31, 2005	--	2,375	--	--	2,375

 

 

The following table provides additional information regarding our combined revenues and costs and expenses for the periods indicated:

 

	For Year Ended December 31,
	2006	2005	2004
Combined revenues
Sales of natural gas	$  816,183	$  858,087	$  649,889
Transportation - natural gas	10,064	8,606	8,533
Transportation - petrochemicals	39,087	33,866	40,975
Storage	59,144	52,838	49,534
Total	$  924,478	$  953,397	$  748,931
Combined cost and expenses
Cost of natural gas sales	$  795,181	$  836,497	$  623,531
Operating expenses	50,461	53,089	43,646
Depreciation, amortization and accretion	21,443	19,453	18,374
Loss (gain) on sale of assets	(25)	5	(7)
General and administrative costs	3,486	4,483	5,442
Total	$  870,546	$  913,527	$  690,986

 

Revenues from the purchase and resale of natural gas included in the Natural Gas Pipelines & Services segment, accounted for 88%, 90% and 87% of total combined revenues for the years ended December 31, 2006, 2005 and 2004, respectively. The cost of natural gas sales accounted for 92%, 92%

 

 

 

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and 91% of total combined operating costs and expenses for the years ended December 31, 2006, 2005 and 2004, respectively.

 

Revenues from Enterprise Products Partners accounted for 13%, 9% and 11% of total combined revenues for the years ended December 31, 2006, 2005 and 2004, respectively. Enterprise Products Partners accounted for 100% of the revenues recorded by our Petrochemical Pipeline Services segment in each period presented. Enterprise Products Partners accounted for 34%, 33% and 34% of the revenues recorded by our NGL & Petrochemical Storage Services segment for the years ended December 31, 2006, 2005 and 2004, respectively.

 

Revenues from Evangeline, our unconsolidated affiliate (see Note 7), accounted for 30%, 35% and 32% of total combined revenues for the years ended December 31, 2006, 2005 and 2004, respectively. See Note 6 for information regarding our related party transactions.

 

In 2006, ExxonMobil Gas & Power Marketing Company (“EOM”) accounted for 9.9% of our combined revenues and 10.2% of revenues of our Natural Gas Pipelines & Services segment. In 2005, EOM accounted for 9.1% of our combined revenues and 9.3% of revenues of our Natural Gas Pipelines & Services segment. In 2004, CF Industries, Inc. accounted for 10.9% of our combined revenues and 12.4% of revenues of our Natural Gas Pipelines & Services segment.

 

 

Note 12.  Commitments and Contingencies

 

Litigation

 

On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we insure against various business 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 indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activity.

 

In 1997, Acadian Gas and numerous other energy companies were named as defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to under report the heating value, as well as the volumes, of natural gas produced from federal and Native American lands. The complaint alleges that the U.S. Government was deprived of royalties as a result of this conspiracy. The plaintiff in this case seeks royalties that he contends the U.S. government should have received had the heating value and volume been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). On October 20, 2006, the U.S. District Court dismissed all of Grynberg’s claims with prejudice. We expect Grynberg to appeal.

 

We are not aware of any other significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

 

Redelivery Commitments

 

We transport and store natural gas and store NGL and petrochemical products for third parties under various contracts. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. We are insured for any physical loss of such volumes resulting from catastrophic events. At December 31, 2006 and 2005, NGL and petrochemical products aggregating 8.5 million barrels and 15.2 million barrels, respectively, were due to be redelivered to their owners along with 748 BBtus and 730 BBtus, respectively, of natural gas.

 

 

 

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Contractual Obligations

 

The following table summarizes our significant contractual obligations at December 31, 2006. This table does not reflect long-term debt obligations of the Partnership incurred in connection with its initial public offering at February 5, 2007 (see Note 15).

 

				Payment or Settlement due by Period
Contractual Obligations				Total	2007	2008	2009	2010	2011	Thereafter
Operating lease obligations:
	Underground natural gas storage cavern			$      2,808	$         468	$         468	$         468	$         468	$         468	$         468
	Right-of-way agreements			$         454	$           74	$           85	$           13	$           13	$           30	$         239
Purchase obligations:
	Product purchase commitments:
		Estimated payment obligations:
			Natural gas	$  920,736	$  153,316	$  153,736	$  153,316	$  153,316	$  153,316	$  153,736
			Other	$      5,578	$      2,317	$      2,182	$      1,079	$            --	$            --	$            --
		Underlying major volume commitments:
			Natural gas (in BBtus)	109,600	18,250	18,300	18,250	18,250	18,250	18,300
	Capital expenditure commitments			$    11,273	$    11,273	$            --	$            --	$            --	$            --	$            --

 

Operating lease obligations.  We lease certain property, plant and equipment under non-cancelable and cancelable operating leases. Amounts shown in the preceding table represent our minimum cash lease payment obligations under operating leases with terms in excess of one year for the periods indicated.

 

Acadian Gas leases an underground natural gas storage cavern that is integral to its operations. The primary use of this cavern is to store natural gas held-for-sale on a demand basis by Acadian Gas. The current term of the cavern lease expires in December 2012. The term of this contract does not provide for an additional renewal period, but it requires the lessor to enter into negotiations with us under similar terms and conditions if we wish to extend the lease agreement beyond December 2012.

 

In addition, our pipeline operations have entered into leases for land held pursuant to right-of-way agreements. Our significant right-of-way agreements have original terms that range from five to 50 years and include renewal options that could extend the agreements for up to an additional 25 years. Our rental payments are generally at fixed rates, as specified in the individual contracts, and may be subject to escalation provisions for inflation and other market-determined factors.

 

Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments, if any, are expensed as incurred. In general, we are required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets attributable to our operations are charged to expense as incurred. We have not made any significant leasehold improvements during the periods presented. Lease expense included in operating income was $1.3 million, $1.2 million and $1.2 million for the year ended December 31, 2006, 2005 and 2004, respectively.

 

Purchase Obligations.  We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (unconditional) on us that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.

 

Acadian Gas has a product purchase commitment for the purchase of natural gas in Louisiana from the co-venture party in Evangeline (see Note 7). This purchase agreement expires in January 2013. Our purchase price under this contract approximates the market price of natural gas at the time we take delivery of the volumes. The preceding table shows the volume we are committed to purchase and an estimate of our future payment obligations for the periods indicated. Our estimated future payment obligations are based on the contractual price at December 31, 2006 applied to all future volume

 

 

 

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commitments. Actual future payment obligations may vary depending on market prices at the time of delivery.

 

At December 31, 2006, we do not have any product purchase commitments with fixed or minimum pricing provisions having remaining terms in excess of one year.

 

We also have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services to be rendered or products to be delivered in connection with our capital spending programs. The preceding table shows these capital project commitments for the periods indicated.

 

At December 31, 2006, we had approximately $11.3 million in outstanding purchase commitments. These commitments primarily relate to our announced expansions of the DEP South Texas NGL Pipeline System and the Mont Belvieu Caverns’ storage facility, which are expected to be completed in 2007.

 

 

Note 13.  Significant Risks and Uncertainties

 

Nature of Operations

 

Our combined results of operations, cash flows and financial position may be adversely affected by a variety of factors affecting our industry and specific businesses, including:

 

§

a reduction in demand for NGL and petrochemical storage services provided by Mont Belvieu Caverns caused by fluctuations in NGL and petrochemical prices and production due to weather and other natural and economic forces;

 

§

a reduction in demand for natural gas transportation services and natural gas consumption in the areas served by Acadian Gas; or

 

§

a reduction in propylene transportation volumes by shippers on the petrochemical pipelines owned by Lou-Tex Propylene and Sabine Propylene.

 

In general, a reduction in demand for NGL and petrochemical products and natural gas by the petrochemical, refining or heating industries could result from (i) a general downturn in economic conditions, (ii) reduced demand by consumers for the end products made with products we handle, (iii) increased governmental regulations or (iv) other reasons.

 

Credit Risk Due to Industry Concentration

 

A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.

 

Counterparty Risk with Respect to Financial Instruments

 

In those situations where we are exposed to credit risk in our financial instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral nor do we anticipate nonperformance by our counterparties.

 

 

 

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Weather-Related Risks

 

Our assets are located along the U.S. Gulf Coast in Texas and Louisiana, which are areas prone to suffer tropical weather events such as hurricanes. If we were to experience a significant weather-related loss for which we were not fully insured, it could have a material impact on our combined financial position, results of operations and cash flows. Likewise, if any of our significant customer or supplier groups experience losses related to storm events, it could have a material impact on our combined financial position, results of operations and cash flows.

 

 

Note 14. Quarterly Financial Information (Unaudited)

 

The following table presents selected quarterly financial data for the years ended December 31, 2006 and 2005 (dollars in thousands):

 

					First	Second	Third	Fourth
					Quarter	Quarter	Quarter	Quarter
For the Year Ended December 31, 2006:
	Revenues				$  283,063	$  220,728	$  236,311	$  184,376
	Operating income				12,098	11,726	16,454	14,612
	Income before changes in accounting principles				12,102	11,705	16,456	15,065
	Net income				12,111	11,705	16,456	15,065
For the Year Ended December 31, 2005:
	Revenues				$  185,176	$  214,853	$  249,375	$  303,993
	Operating income				9,604	10,407	11,546	8,644
	Income before changes in accounting principles				9,604	10,407	11,546	8,112
	Net income				9,604	10,407	11,546	7,530

 

 

Note 15. Subsequent Event

 

Initial Public Offering of Duncan Energy Partners L.P.

 

On February 5, 2007, the Partnership completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at a price of $21.00 per unit, which generated net proceeds to the Partnership of $291.3 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, the Partnership distributed $260.6 million of these net proceeds to EPOLP, along with $198.9 million in borrowings under its revolving credit facility (see below) and a final amount of 5,351,571 common units of the Partnership. The Partnership used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to EPOLP, resulting in the final amount of 5,351,571 common units beneficially owned by EPOLP. EPOLP used the cash it received from the Partnership to temporarily reduce amounts outstanding under its revolving credit facility.

 

In connection with its initial public offering, the Partnership entered into a $300 million revolving credit facility, which includes a $30 million sublimit for swingline loans. On February 5, 2007, the Partnership borrowed $200 million under this facility to fund the $198.9 million cash distribution to EPOLP and the remainder to pay debt issuance costs. This credit facility matures in February 2011 and will be used by the Partnership in the future to fund working capital requirements, make payments in connection with acquisitions and for general partnership purposes. The Partnership can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. The Partnership’s borrowings under this credit facility are unsecured general obligations that are non-recourse to DEP GP.

 

 

 

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Enterprise Products Partners may contribute other equity interests in its subsidiaries to the Partnership in the near term and use the proceeds it receives to fund its capital spending program. Enterprise Products Partners has no obligation or commitment to make such contributions to the Partnership.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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SCHEDULE II

 

DUNCAN ENERGY PARTNERS PREDECESSOR

VALUATION AND QUALIFYING ACCOUNTS

 

 

						Additions
				Balance At		Charged To		Charged To
				Beginning		Costs And		Other				Balance At
Description				Of Period		Expenses		Accounts		Deductions		End of Period
Accounts receivable – trade
Allowance for doubtful accounts
	2006	(1)		$    3,372		$       --		$       --		$   (2,970)		$       402
	2005			3,457		--		--		(85)		3,372
	2004	(1)		6,935		--		--		(3,478)		3,457
(1)    In 2006 and 2004, we adjusted the allowance account for the receipt of a contingent asset related to a prior business acquisition.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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DUNCAN ENERGY PARTNERS L.P.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Partners of Duncan Energy Partners L.P.

 

We have audited the accompanying balance sheet of Duncan Energy Partners L.P. (the “Partnership”) as of December 31, 2006. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of the Partnership at December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

 

/s/  Deloitte & Touche LLP

 

Houston, Texas

April 2, 2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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DUNCAN ENERGY PARTNERS L.P.

BALANCE SHEET

AT DECEMBER 31, 2006

 

 

ASSETS
Cash	$         3,003
Deferred offering costs	2,682,313
Prepaid and other assets	4
Total assets	$  2,685,320
LIABILITIES AND PARTNERS’ EQUITY
Accounts payable	$     433,975
Accounts payable — related party	2,248,338
Partners’ equity:
Limited partner	2,947
General partner	60
Total liabilities and partners’ equity	$  2,685,320

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Note to Balance Sheet

 

 

 

 

F-39

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DUNCAN ENERGY PARTNERS L.P.

NOTE TO BALANCE SHEET

 

Nature of operations

 

Duncan Energy Partners L.P.  (the “Partnership”) was formed on September 29, 2006 as a Delaware limited partnership to acquire ownership interests in midstream energy businesses from subsidiaries of Enterprise Products Partners L.P. These ownership interests were acquired by the Partnership at the closing of its initial public offering on February 5, 2007.

 

The business of the Partnership consisted of (i) receiving, storing and delivering natural gas liquids (“NGLs) and petrochemical products, (ii) gathering, transporting, storing and marketing natural gas and (iii) transporting NGLs and propylene. The Partnership acquired a 66% interest in the following companies, all of which were wholly-owned subsidiaries of Enterprise Products Partners L.P. at December 31, 2006:

 

§

Mont Belvieu Caverns, LLC  (“Mont Belvieu Caverns”), which receives, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast;

 

§

Acadian Gas, LLC   (“Acadian Gas”), which gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of natural gas transmission and gathering pipelines and a leased storage cavern;

 

§

Enterprise Lou-Tex Propylene Pipeline L.P.  (“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas;

 

§

Sabine Propylene Pipeline L.P.  (“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana; and

 

§

South Texas NGL Pipelines, LLC  (“South Texas NGL”), which transports NGLs from Corpus Christi, Texas to Mont Belvieu, Texas. A 220-mile pipeline that formed the largest part of a pipeline system was purchased by Enterprise Products Partners in August 2006. The Partnership also purchased a 10-mile segment of 18-inch pipeline in January 2007 from TEPPCO. This system became operational and began transporting NGL products in January 2007 after under going modifications, extensions and interconnections. Additional expansions to this system are scheduled to be completed during 2007.

 

Enterprise Products Partners L.P. control of the Partnership’s 2% general partner, DEP Holdings, LLC (the “General Partner”), which directs the operations of the Partnership. Enterprise Products Operating L.P. (a wholly owned subsidiary of Enterprise Products Partners L.P.) is the organizational limited partner of the Partnership. The Partnership, the General Partner, Enterprise Products Operating L.P. and Enterprise Products Partners L.P. are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc.

 

Deferred offering costs

 

Direct offering costs representing specific legal, accounting, and other third party services incurred to date in connection with the anticipated initial public offering of the Partnership will be deferred and charged against the gross proceeds of the offering. Offering costs paid by related parties prior to the offering will be reimbursed from the proceeds of the offering. At this time there are no other obligations for organizational costs intended to be reimbursed to related parties.

 

 

 

 

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Subsequent Event

 

Initial Public Offering of Duncan Energy Partners L.P.

 

On February 5, 2007, the Partnership completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at a price of $21.00 per unit, which generated net proceeds to the Partnership of $291.3 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, the Partnership distributed $260.6 million of these net proceeds to EPOLP, along with $198.9 million in borrowings under its revolving credit facility (see below) and a final amount of 5,351,571 common units of the Partnership. The Partnership used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to EPOLP, resulting in the final amount of 5,351,571 common units beneficially owned by EPOLP. EPOLP used the cash it received from the Partnership to temporarily reduce amounts outstanding under its revolving credit facility.

 

In connection with its initial public offering, the Partnership entered into a $300 million revolving credit facility, which includes a $30 million sublimit for swingline loans. On February 5, 2007, the Partnership borrowed $200 million under this facility to fund the $198.9 million cash distribution to EPOLP and the remainder to pay debt issuance costs. This credit facility matures in February 2011 and will be used by the Partnership in the future to fund working capital requirements, make payments in connection with acquisitions and for general partnership purposes. The Partnership can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. The Partnership’s borrowings under this credit facility are unsecured general obligations that are non-recourse to DEP GP.

 

Enterprise Products Partners may contribute other equity interests in its subsidiaries to the Partnership in the near term and use the proceeds it receives to fund its capital spending program. Enterprise Products Partners has no obligation or commitment to make such contributions to the Partnership.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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DEP HOLDINGS, LLC

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Owner of DEP Holdings, LLC

 

We have audited the accompanying balance sheet of DEP Holdings, LLC (the “General Partner”) as of December 31, 2006. This financial statement is the responsibility of the General Partner’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. The General Partner is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the General Partner’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of the General Partner at December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ Deloitte & Touche LLP

 

Houston, Texas

April 2, 2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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DEP HOLDINGS, LLC

BALANCE SHEET

AT DECEMBER 31, 2006

 

 

ASSETS
Cash	$     943
Prepaid and other current assets	4
	947
Investment in Duncan Energy Partners L.P.	60
Total assets	$  1,007
MEMBER’S EQUITY
Member’s equity	$  1,007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Note to Balance Sheet

 

 

 

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DEP HOLDINGS, LLC

NOTE TO BALANCE SHEET

 

Nature of Operations

 

DEP Holdings, LLC  (the “General Partner”) is a Delaware limited liability company that was formed on September 29, 2006, to own a 2% general partner interest in Duncan Energy Partners L.P. (the “Partnership”), a Delaware limited partnership. The General Partner is wholly owned by Enterprise Products Operating L.P., a wholly owned subsidiary of Enterprise Products Partners L.P.

 

On October 20, 2006, Enterprise Products Operating L.P. contributed $1,000 to the General Partner, which used $60 of such funds to acquire a general partner interest in the Partnership. The Partnership was formed on September 29, 2006 and its purpose is to acquire ownership interests in midstream energy businesses of Enterprise Products Partners L.P. Such ownership interests were acquired by the Partnership at the closing of the Partnership’s initial public offering on February 5, 2007. The Partnership, the General Partner, Enterprise Products Operating L.P. and Enterprise Products Partners L.P. are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

F-44

 

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