UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

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

For the transition period from                      to                     .

DUNCAN ENERGY PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

Delaware		20-5639997
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1100 Louisiana, 10th Floor, Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

(713) 381-6500
(Registrant’s Telephone Number, Including Area Code)

Title of Each Class		Name of Each Exchange On Which Registered
Common Units		New York Stock Exchange

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 þ

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 þ

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 þ No o

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No þ

The aggregate market value of the common units of Duncan Energy Partners L.P. held by non-affiliates at June 30, 2007, based on the closing price of such equity securities in the daily composite list for transactions on the New York Stock Exchange, was approximately $392.4 million. This figure excludes common units beneficially owned by certain affiliates, including (i) Dan L. Duncan and (ii) Enterprise Products Operating LLC. As of February 1, 2008, 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 LLC, the parent company of Duncan Energy Partners L.P.

 

 

DUNCAN ENERGY PARTNERS L.P.
TABLE OF CONTENTS

		Page
		Number
PART I
Items 1 and 2. Business and Properties.			4
Item 1A. Risk Factors.			20
Item 1B. Unresolved Staff Comments.			40
Item 3. Legal Proceedings.			41
Item 4. Submission of Matters to a Vote of Unitholders.			41
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.			41
Item 6. Selected Financial Data.			42
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.			43
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.			61
Item 8. Financial Statements and Supplementary Data.			63
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.			108
Item 9A. Controls and Procedures.			108
Item 9B. Other Information.			110
PART III
Item 10. Directors, Executive Officers and Corporate Governance.			111
Item 11. Executive Compensation.			116
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.			122
Item 13. Certain Relationships and Related Transactions, and Director Independence.			124
Item 14. Principal Accountant Fees and Services.			132
PART IV
Item 15. Exhibits and Financial Statement Schedules.			133
Signatures			137
Computation of Ratio of Earnings to Fixed Charges
List of Subsidiaries
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 1350
Certification Pursuant to Section 1350

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 1, 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 prior to February 5, 2007, these terms are intended to mean the combined business and operations of Duncan Energy Partners Predecessor.

     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.

     References to “DEP GP” mean DEP Holdings, LLC, which is our general partner.

     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 LLC. Enterprise Products Partners is a publicly traded partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”

     References to “EPO” mean our Parent, which is Enterprise Products Operating LLC and its consolidated subsidiaries. EPO owns a 100% interest in the Partnership’s general partner and is a significant owner of the Partnership’s common units.

     References to “EPGP” mean Enterprise Products GP, LLC, the general partner of Enterprise Products Partners.

     References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.”

     References to “TEPPCO GP” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings L.P.

     References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is LE GP, LLC (“LEGP”). On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LEGP and Energy Transfer Equity.

     References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., which owns EPGP, TEPPCO GP and limited partner interests in Enterprise Products Partners and TEPPCO. Enterprise GP Holdings is a publicly traded partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.”

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

     References to “EPCO” mean EPCO, Inc. and its wholly-owned private company affiliates, which are related party affiliates to all of the foregoing named entities.

     All of the aforementioned entities are affiliates and under common control of Mr. Dan L. Duncan, the Co-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,” “seek,” “goal,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” 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 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 is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” We are currently engaged in the business of gathering, transporting, marketing and storing natural gas and transporting and storing natural gas liquids (“NGLs”) and petrochemicals. We are owned 98% by our limited partners and 2% by our general partner, DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is responsible for managing all of our operations and activities. EPCO employs all the personnel necessary to operate our assets and manage our business. Our principle executive offices are located at 1100 Louisiana, 10^th Floor, Houston, Texas 77002. Our telephone number is (713) 381-6500 and our website is www.deplp.com.

     We were formed by EPO in September 2006 to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO. On February 5, 2007, we completed our initial public offering of 14,950,000 common units, which generated net proceeds of $290.5 million. We distributed $260.6 million of such net proceeds, plus $198.9 million in borrowings under our credit facility along with a final amount of 5,351,571 of our common units to EPO as consideration for certain equity interests it contributed to us (see below) at the time of our initial public offering.

     Prior to completion of our initial public offering, our subsidiaries (Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL) were wholly owned by EPO. On February 5, 2007, EPO contributed 66% of its equity interests in these five subsidiaries to us. These subsidiaries continue to be a part of EPO’s integrated network of midstream energy assets. We believe that the operational significance of our assets to EPO, 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.

     EPO operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years prior to its contribution of equity interests in such entities to us. On February 5, 2007, DEP Operating Partnership directly or indirectly assumed these responsibilities.

     EPO may contribute or sell other equity interests in its subsidiaries or other of its or its subsidiaries’ assets to the Partnership and use the proceeds it receives to fund its capital spending program. However, EPO has no obligation or commitment to make such contributions or sales to the Partnership.

     In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with the Partnership in accordance with the existing sharing ratio of 66% funded by the Partnership and 34% funded by EPO. See our discussion of “Financing Activities” beginning on page 55 of this annual report for information regarding recent cash contributions made by EPO in connection with the Omnibus Agreement and Mont Belvieu Caverns’ limited liability company agreement.

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:

	§		optimize the benefits of our economies of scale, strategic location and pipeline connections serving our natural gas, NGL, petrochemical and refining markets;
	§		manage our existing and future asset portfolio to minimize the volatility of our cash flows;
	§		invest in organic growth projects to capitalize on market opportunities that expand our asset base and generate additional cash flow; and
	§		pursue acquisitions of assets and businesses from related parties, or in accordance with our business opportunity agreements, from third parties.

Financial Information by Business Segment

     For information regarding our business segments, see Note 14 of the Notes to Financial Statements included under Item 8 of this annual report.

Recent Developments

     For information regarding our recent developments, see “Overview of Business – Recent Developments” included under Item 7 of this annual report, which is incorporated by reference into this Item 1.

Segment Discussion

     We are currently engaged in the business of gathering, transporting, marketing and storing natural gas and transporting and storing NGLs and petrochemicals. We have four reportable business segments:

	§		NGL & Petrochemical Storage Services;
	§		Onshore Natural Gas Pipelines & Services;
	§		Petrochemical Pipeline Services; and
	§		NGL Pipelines & 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. In January 2008, we renamed our

Natural Gas Pipelines & Services segment to Onshore Natural Gas Pipelines & Services. Likewise, we changed the name of the NGL Pipeline Services segment to NGL Pipelines & Services. Apart from these name changes, no other revisions were made to these segments.

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

     Our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental, safety and other matters. For a discussion of the principal effects such laws and regulations have on our business, see “Regulation” and “Environmental and Safety Matters” included within this Item 1.

     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. 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. In addition, 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 (see Item 13 of this annual report).

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

/d		= per day
BBtus		= billion British thermal units
Bcf		= billion cubic feet
MBPD MMBbls		= thousand barrels per day = million barrels
MMBtus		= million British thermal units
MMcf		= million cubic feet

     The following discussion of our business segments provides information regarding our principal plants, pipelines and other assets. For information regarding our results of operations, including significant measures of historical operating rates, see Item 7 of this annual report.

NGL & Petrochemical Storage Services

     Our NGL & Petrochemical Storage Services business segment consists of three integrated underground storage facilities that are strategically located in Mont Belvieu, Texas. We refer to these storage facilities as Mont Belvieu East, West and North. We have multiple pipelines that interconnect these facilities, and each storage facility is comprised of a network of caverns located several hundred feet below ground. Overall, these facilities consist of 33 storage caverns with an aggregate underground storage capacity of 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, of which we own 66% and EPO owns 34%.

     These assets receive, store and deliver NGLs and petrochemical products 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. Our NGL and petrochemical storage facilities are interconnected by multiple pipelines to other producing and offtake facilities throughout the Gulf Coast, including EPO’s NGL import/export facility located on the Houston Ship Channel, as well as connections to the Rocky

Mountain and Midwest regions via the Seminole pipeline and to Louisiana via EPO’s Lou-Tex NGL pipeline.

     NGL products (ethane, propane, normal butane, isobutane and natural gasoline) are used as raw materials by the petrochemical industry, feedstocks by refiners in the production of motor gasoline and by industrial and residential users as fuel. Ethane is primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, principally for use in refinery alkylation to enhance the octane content of motor gasoline, in the production of isooctane and other octane additives, and in the production of propylene oxide. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline or as a petrochemical feedstock.

     We also store certain petrochemicals such as propylene (chemical, polymer and refinery grades) and ethylene. Chemical-grade propylene is a petrochemical used in plastics, synthetic fibers and foams. Polymer-grade propylene is primarily used in the manufacture of polypropylene, which has a variety of end uses, including packaging film, carpet and upholstery fibers and plastic parts for appliances, automobiles and medical devices. Refinery grade propylene is produced by refineries and is used as a feedstock in the production of polymer-grade and chemical-grade propylene. Ethylene is also a key building block for the petrochemical industry. Ethylene derivatives are used in film applications for packaging, carrier bags and trash liners. Other applications include injection molding, pipe extrusion and cable sheathing and insulation, as well as extrusion coating of paper and cardboard.

     Mont Belvieu Caverns derives essentially all of its revenues from four main sources. These sources are (i) storage reservation fees, (ii) excess storage fees, (iii) throughput fees and (iv) brine production fees. 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.

     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.

     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 Louisiana Gulf Coast. Our five largest third-party customers, which accounted for 31.7% of our total storage revenues for the year ended December 31, 2007, were ExxonMobil, Dow, Shell, Louis Dreyfus, and Occidental.

     Underground storage services we provide to EPO for the storage of NGLs and petrochemicals accounted for 40% of our total storage revenues for the year ended December 31, 2007. EPO has eight storage contracts with Mont Belvieu Caverns that include (i) multi-product fungible storage for its NGL marketing activities and feedstocks for its isomerization, isooctane, NGL fractionation, and propylene fractionation businesses and (ii) segregated product storage for refinery-grade and polymer-grade propylene produced at propylene fractionation facilities. Six of these contracts have ten-year terms while two have five-year terms. We recorded $27.3 million in storage revenues from EPO for the eleven months ended December 31, 2007 and $20.1 million and $17.6 million for the years ended December 31, 2006 and 2005, respectively. See Item 13 of this annual report for additional information regarding our ongoing relationship with EPO.

     Seasonality. We operate our NGL and petrochemical 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, storage volumes linked to imports peak during the spring and summer months and those associated with exports 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 and petrochemical storage business are integrated major oil companies, chemical companies and other storage and pipeline companies. We primarily compete against LDH Energy Mont Belvieu L.P.; Targa Resources, Inc.; Texas Brine Company, LLC and ONEOK Partners, L.P. The principal competitive factors affecting our product storage business are storage fees, 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, which has resulted in many long-standing customer relationships. We also believe that the number of pipelines connected to our storage facilities allows us to offer customers a wider variety of receipt and delivery options with respect to key Gulf Coast petrochemical plants, NGL fractionators and other users of the products we store. Furthermore, we believe that our emphasis on maintenance and safety provides our customers with a high level of confidence in our operational dependability.

     Properties. The following information summarizes the significant assets that comprise our Mont Belvieu East, West and North storage facilities at December 31, 2007.

	§		Mont Belvieu East Facility.  The Mont Belvieu East facility is the largest of the three facilities. This facility consists of 13 storage caverns available for service with an underground storage capacity of approximately 55 MMBbls and an above-ground brine pit with a capacity of approximately 10 MMBbls. This facility also has two brine production wells.
	§		Mont Belvieu West Facility.  The Mont Belvieu West facility consists of 10 caverns available for service with an underground storage capacity of approximately 15 MMBbls and an above-ground brine pit with a capacity of approximately 2 MMBbls.
	§		Mont Belvieu North Facility.  The Mont Belvieu North facility consists of 10 caverns available for service with an underground storage capacity of approximately 30 MMBbls and an above-ground brine pit with a capacity of approximately 8 MMBbls.

     We have initiated several projects to improve the integration of our three Mont Belvieu storage facilities. These projects include additional pipelines to more efficiently connect the facilities and the drilling of additional entry points into certain wells to increase flow rates.

Onshore Natural Gas Pipelines & Services

     Our Onshore 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 South 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 pipelines and smaller diameter lateral and gathering pipelines with an aggregate throughput capacity of approximately 1.0 Bcf/d and 3.0 Bcf of storage capacity. The Acadian Gas System is owned by Acadian Gas.

     The Acadian Gas System is currently connected to approximately 116 customers with an approximate total natural 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. The system’s customer base is diversified, with its largest customer, ExxonMobil, representing only 10.1% of its total revenue in 2007 and the top ten customers representing only 39.1% of its total revenue in 2007.

     The Acadian Gas System has over 150 direct physical connections to end users. In addition, the system interconnects with 12 interstate and four 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 electric generation facilities with over 6,000 megawatts of generating capacity. These numerous interconnections allow the Acadian Gas System to leverage price 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 provides fee-based gas transportation services for producers and gas marketing companies under intrastate and interruptible Natural Gas Act (“NGA”) 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 Coral Energy Resources, ExxonMobil, BG Energy Merchants and BP Energy. 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 term of this agreement expires in November 2009. During 2007, ExxonMobil shipped approximately 133 BBtus/d on the Acadian Gas System, utilizing the system as the primary fuel gas pipeline service provider for its source Baton Rouge refinery and chemical complex.

     The majority of our natural gas sales using 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 customer’s natural gas requirements, which may vary hourly, daily and monthly. Our natural gas sales arrangements are typically implemented under contracts with market-based pricing indices that correspond to the pricing indices utilized in our gas purchasing activities. The electric utility and industrial customers of Acadian Gas normally consume 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 their customers.

     The most significant Acadian Gas natural gas sales contract is a 21-year arrangement with Evangeline Gas Pipeline Company, L.P. (“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 hourly, daily, monthly and annual basis. The gas sales contract provides for minimum annual quantities of 36.75 BBtus until the contract expires in January 2013 (which is coterminous with the natural gas purchase commitment with ConocoPhillips described below). 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.

     In support of its natural gas sales activities, Acadian Gas has entered into gas purchase arrangements with a number of suppliers. The system currently purchases gas supply from 51 gas producers through 65 gas production receipt locations. The Acadian Gas System also procures gas supply from market center pipeline hubs such as the Henry Hub and the Nautilus Hub, natural gas processing plants and third party natural gas pipelines. The Acadian Gas System has approximately 50 pipeline interconnects with 12 interstate pipeline systems, and four unaffiliated intrastate pipeline systems.

     Substantially all of the Acadian Gas System’s natural gas requirements are purchased under contracts that contain pricing based on market-based pricing indices. The Acadian Gas System’s most significant long-term gas purchase commitment is with ConocoPhillips. This purchase contract expires in January 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, consistent in structure to the minimum annual obligations between the 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 18.2 BBtus in 2007, 17.9 BBtus in 2006 and 17.4 BBtus in 2005. Amounts paid for natural gas purchased under this contract totaled $127.1 million in 2007, $134.9 million in 2006 and $148.3 million in 2005.

     The Acadian Gas System includes a bi-directional interconnect with the Henry Hub, which is generally considered to be one of the most active 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 physical 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 EPO. 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.

     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. We believe that the transportation fees and natural gas sales prices we charge are competitive with those charged by other pipeline and gas marketing companies because most prices in this business are based on published indices. We also believe that our competitive position is enhanced due to a number of long-standing customer relationships. Due to the limited number of alternative delivery pipeline connections, we have been able to retain our customers for many years. Although our competitors could connect their systems to our customers, the construction costs involved would typically be prohibitive. Lastly, we believe that our emphasis on maintenance and safety provides our customers with confidence in our operational dependability and flexibility in meeting their natural gas requirements.

     Properties. The Acadian Gas System includes the following assets:

	§		Acadian Pipeline.  The Acadian pipeline is located in southern Louisiana and consists of approximately 438 miles of high-pressure transmission pipelines and smaller diameter lateral and gathering lines ranging from 12 inches to 24 inches in diameter. The Acadian pipeline receives natural gas at numerous interconnections with natural gas production facilities and from third-party pipelines, and delivers the natural gas to customers’ facilities in southern Louisiana. Through numerous interconnections with other pipelines, including receipt and delivery capability at the 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.
	§		Cypress Pipeline.  The Cypress pipeline is located in south central Louisiana and consists of approximately 577 miles of transmission pipelines and smaller diameter lateral and gathering lines ranging from 10 inches to 22 inches in diameter. This pipeline has interconnections with many of the interstate and intrastate pipeline systems operating in southern Louisiana and has a throughput capacity of approximately 350 MMcf/d. The Cypress pipeline was originally built to gather onshore Louisiana natural gas supplies and to provide natural gas pipeline service to the greater Baton Rouge industrial market, in particular, the ExxonMobil Baton Rouge Refinery. Through the 1950’s and 1960’s, it was expanded to access the interstate pipeline supply network and the Geismar, Louisiana and Donaldsonville, Louisiana industrial market areas. The Cypress pipeline also has the capability to access deepwater gas production through an interconnection with the Nautilus Gas Pipeline system and numerous third-party pipelines.
	§		Evangeline Pipeline.  The Evangeline pipeline is a 27-mile pipeline extending from Taft, Louisiana to Westwego, Louisiana. The Evangeline pipeline, which consists mainly of transmission pipelines ranging from 20 inches to 26 inches in diameter, connects with three Entergy Louisiana natural gas-fired electric generation stations, the Acadian pipeline and a pipeline owned by the Columbia Gulf Transmission Company. We indirectly own approximately 49.5% of the ownership interests in the Evangeline pipeline. A subsidiary of ConocoPhillips and a private investor own the remaining interests in the entity that owns the Evangeline pipeline.
	§		Underground Storage Facility.  The storage assets in the Acadian Gas System consist of a leased underground natural gas storage facility located at the center of the Acadian Pipeline near Napoleonville, Louisiana. The storage facility has approximately 3.0 Bcf of storage capacity with 220 MMcf/d of withdrawal capacity and a maximum of 80 MMcf/d of injection capacity. This

facility is designed to handle high levels of injections and withdrawals of natural gas to meet load swings and to cover major supply interruption events, such as hurricanes and temporary losses of production. In addition, the storage facility permits sustained periods of high natural gas deliveries and has the ability to switch quickly from full injection to full withdrawal. We lease this storage facility from an affiliate of Shell under an agreement that extends through December 31, 2012. The term of this contract does not provide for an additional renewal period. However, Shell has agreed to enter into negotiations with us under similar terms and conditions for an extension if we wish to extend the lease agreement beyond December 2012. Acadian Gas is the operator of this underground storage facility and utilizes 75% of the leased storage, withdrawal and injection capacity. We sublease the remaining 25% of the capacity to a third party.

     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. The following table summarizes the Acadian Gas System’s natural gas sales and transportation volumes for the periods indicated (volumes in BBtus/d):

		Year Ended December 31,
		2007				2006				2005
Natural gas transportation volumes			416				434				323
Natural gas sales volumes			308				325				317
Total natural gas throughput volumes			724				759				640

     Entergy Louisiana has the option to purchase the Evangeline pipeline for a nominal price, plus the assumption of all of Evangeline’s obligations under the gas sales contract. The option period begins on the earlier of July 2010 or upon the payment in full of Evangeline’s debt obligations, and terminates in December 2012. We do not 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. For information regarding Evangeline’s debt obligations, please see Note 11 of the Notes to Financial Statements included under Item 8 of this annual report.

Petrochemical Pipeline Services

     Our Petrochemical Pipeline Services segment reflects the operations of our Lou-Tex Propylene Pipeline and Sabine Propylene Pipeline systems. These systems provide for the transportation of propylene in Texas and Louisiana.

     The Lou-Tex Propylene Pipeline is a 263-mile pipeline used to transport chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas. Shell and ExxonMobil are the only customers of this pipeline. The chemical-grade propylene we transport for Shell originates at its underground storage facility located in Sorrento, Louisiana and is delivered to various receipt points between Sorrento, Louisiana and Mont Belvieu, Texas. The receipt points on the Lou-Tex Propylene Pipeline include connections with Vulcan, Westlake Lake Charles, Beaumont Novus, and Shell’s Texas chemical-grade propylene delivery system. The chemical-grade propylene we transport for ExxonMobil originates from its refining and chemical complex located in Baton Rouge, Louisiana and is delivered to either ExxonMobil’s customers or to an underground storage well located in Mont Belvieu, Texas owned by Mont Belvieu Caverns.

     The Sabine Propylene Pipeline consists of a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to an interconnect with EPO’s Lake Charles propylene pipeline in Cameron Parish, Louisiana. Shell is the sole customer of this pipeline. The polymer-grade propylene transported for Shell originates from the TOTAL/BASF Port Arthur cracker facility and is delivered to the Lyondell Basell polypropylene facility in Lake Charles, Louisiana.

     Revenues recorded for the Lou-Tex Propylene Pipeline and Sabine Propylene Pipeline are primarily based on exchange agreements with Shell and ExxonMobil. As a result of these exchange agreements, we agree to receive propylene in one location and deliver propylene at another location for a fee. The following information summarizes the exchange agreements with Shell and ExxonMobil:

	§		Shell Exchange Agreements.  The term of the Lou-Tex Propylene Pipeline agreement expires in March 2020, but will continue on an annual basis subject to termination by either party. The exchange fees paid by Shell to Lou-Tex Propylene are fixed until such time as a published power index in Louisiana becomes available and the parties agree to use such index. The term of the Sabine Propylene Pipeline agreement expires in November 2011, but will continue on an annual basis subject to termination by either party. The exchange fees paid by Shell to Sabine Propylene are adjusted yearly based on the U.S. Department of Labor wage index and the yearly operating costs of the Sabine Propylene Pipeline. Shell is obligated to meet minimum delivery requirements under the Lou-Tex Propylene and Sabine Propylene agreements. If Shell fails to meet such minimum delivery requirements, it is obligated to pay a deficiency fee to us.
	§		ExxonMobil Exchange Agreement.  The term of the Lou-Tex Propylene Pipeline exchange agreement expires in June 2008, but will continue on a monthly basis subject to a two-year termination notice initiated by either party. The exchange fees paid by ExxonMobil are based on the volume of chemical-grade propylene delivered.

     The exchange agreements with Shell and ExxonMobil were assigned by EPO 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 EPO were based on the maximum tariff rate allowed for each system. We continued to charge EPO 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 under the terms of their respective Exchange Agreements.

     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.

     Properties. The Lou-Tex Propylene Pipeline consists of a 263-mile, 10-inch pipeline that was constructed in 1997 and acquired by EPO in March 2000 from an affiliate of Shell. The Sabine Propylene Pipeline consists of a 21-mile, 8-inch pipeline that was constructed by EPO and placed into service in 2002. The following table summarizes average throughput rates for each of these petrochemical pipelines for the periods indicated (volumes in MBPD):

		Approximate				Year Ended December 31,
		Capacity (1)				2007				2006				2005
Lou-Tex Propylene Pipeline			53				25				27				23
Sabine Propylene Pipeline			21				12				10				10

NGL Pipelines & Services

     Our NGL Pipelines & Services segment reflects the operations of our DEP South Texas NGL Pipeline System, which is a 286-mile intrastate pipeline system used to transport NGLs from South Texas to Mont Belvieu, Texas. The system became operational in January 2007, and NGL transportation rates averaged 73 MBPD for the year ended December 31, 2007.

     The sole customer of our DEP South Texas NGL Pipeline System is EPO, which uses the pipeline to ship NGLs processed at its Shoup fractionation plant in Corpus Christi, Texas, its Armstrong fractionation plant located near Victoria, Texas and NGLs purchased from third parties in South Texas to Mont Belvieu, Texas. In 2007, we entered into a ten-year transportation contract with EPO that includes all of the volumes of NGLs transported on the DEP South Texas NGL Pipeline System. Under this contract, EPO 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 EPO 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, EPO retains title and the associated commodity risk.

     Revenues from the dedication fee represent substantially all of the revenues for this business segment. Accordingly, the results of operations for the DEP South Texas NGL Pipeline are dependent upon the level of production of NGLs from the Shoup and Armstrong plants. NGL production volumes from these facilities have varied during recent periods and may vary in the future. If one of the plants shuts down or otherwise decreases production, our revenues would decrease.

     The Shoup plant, located in Corpus Christi, Texas, separates mixed NGLs into purity products such as ethane and propane and has a fractionation capacity of 69 MBPD. The Shoup plant receives mixed NGLs from a gathering pipeline network totaling approximately 350 miles that is linked to six natural gas processing plants located in South Texas. The Armstrong fractionator, located in Dewitt County, Texas, has a capacity of 18 MBPD and fractionates mixed NGLs for EPO’s Armstrong natural gas processing plant exclusively. In the aggregate, the Shoup and Armstrong fractionators produced an average of 72 MBPD, 66 MBPD and 65 MBPD during the years ended December 31, 2007, 2006 and 2005, respectively.

     As noted above, the mixed NGLs processed by the Shoup and Armstrong fractionators originate from natural gas processing plants located in South Texas. Based on industry data, we believe that there will be sufficient quantities of natural gas to support the production of mixed NGLs from these processing plants for the next 20 to 40 years. For example, 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. We expect that ongoing natural gas exploration and production activities will result in new volumes that will mitigate the effects of normal depletion rates of existing resource basins.

     Seasonality. Operating results for our DEP South Texas NGL Pipeline do not exhibit a significant degree of seasonality.

     Competition. The DEP South Texas NGL Pipeline is not affected by competition given its long-term transportation agreement with EPO, which is our sole customer on this pipeline.

     Properties. The 286-mile 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 of its development. In August 2006, EPO acquired a 220-mile segment of pipeline, ranging from 12 inches to 16 inches in diameter, from a third party for $97.7 million that was the first step in building the DEP South Texas NGL Pipeline System. This initial segment originates in Corpus Christi, Texas and extends to Pasadena, Texas and has a current NGL transportation capacity of approximately 100 MBPD, which is expandable to 175 MBPD under certain conditions. During Phase I, EPO also constructed approximately 13 miles of pipeline and integrated an existing 32-mile pipeline to connect the Shoup and Armstrong fractionators to the system and entered into a lease with TEPPCO for an 11-mile, 10-inch interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas. In January 2007, EPO acquired an additional 10-mile, 18-inch segment of pipeline that 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. The DEP South Texas NGL Pipeline System was included with the operations and assets contributed to us by EPO at the closing of our initial public offering.

     We are in the final stages of Phase II of the system’s development, which entails the construction of 22 miles of 18-inch pipeline to replace the pipeline we are leasing from TEPPCO and certain other pipeline segments. The Phase II upgrade will provide a significant increase in pipeline capacity and is expected to be operational by the end of the first quarter of 2008.

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.

Regulation

Regulation of Our Intrastate Natural Gas Pipelines and Storage Services

     At the federal level, our gas pipelines and gas storage facilities are subject to regulations of the FERC under the Natural Gas Act (“NGA”). Our natural gas intrastate systems provide transportation and storage pursuant to Section 311 of the NGA and Section 284 of the FERC’s regulations. Under Section 311 of the NGA, 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 are 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.

     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.

     In July 2006, we filed petitions at the FERC 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. In December 2006, the FERC approved an uncontested settlement which established our maximum interruptible transportation rate for Section 311 service. This currently effective rate remains subject to complaint by our shippers. We are required to file another rate

petition on or before July 11, 2009 to justify our current rates or establish new rates for NGA Section 311 service. The Louisiana Public Service Commission also reviews and approves rates for pipelines providing intrastate 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 regulation, the natural gas industry has historically been subject to numerous other forms of federal, state and local regulation.

Sales of Natural Gas

     We are engaged in natural gas marketing activities. The resale of natural gas in interstate commerce made by intrastate pipelines or their affiliates is subject to FERC regulation unless the gas is produced by the pipeline carrier or an affiliate. Under current federal rules, however, the price at which we sell natural gas currently is not regulated, insofar as the interstate market is concerned and, for the most part, is not subject to state regulation. The FERC’s rules require pipelines and their marketing affiliates who sell natural gas in interstate commerce subject to the FERC’s jurisdiction to adhere to a code of conduct prohibiting market manipulation and transactions that have no legitimate business purpose or result in prices not reflective of legitimate forces of supply and demand. Those who violate this code of conduct may be subject to suspension or loss of authorization to perform such sales, disgorgement of unjust profits, or other appropriate non-monetary remedies imposed by the FERC. The FERC currently has a rulemaking pending which would implement revisions to these rules. The FERC is continually proposing and implementing new rules and regulations affecting segments of the natural gas industry. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing activities; however, we believe that any new regulations will also be applied to other natural gas marketers with whom we compete.

Regulation of Our Petrochemical Pipeline Services

     Our Lou-Tex Propylene and Sabine Propylene Pipelines are interstate common carrier pipelines regulated by the Surface Transportation Board (“STB”), a part of the United States Department of Transportation, 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 not unduly discriminatory or preferential. 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 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, 2007, we had a reserve of approximately $0.3 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 CWA imposes substantial civil and criminal penalties for non-compliance. The EPA has promulgated regulations that require us to have permits in order to discharge storm water runoff. The EPA has entered into agreements with states in which we operate whereby the permits are administered by their respective states.

     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, 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 and some states are 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. In the past, although we utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and other materials may have been disposed of or released. In the future, we may be required to remove or remediate these materials.

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. Despite the “petroleum exclusion” of CERCLA that currently encompasses natural gas, we may nonetheless handle “hazardous substances” subject to CERCLA in the course of our operations and our pipeline systems may generate wastes that 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.

     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 federal, state and local governmental authorities and local citizens upon request.

Employees

     Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement. As of December 31, 2007, there were approximately 1,400 EPCO personnel that spend all or a portion of their time engaged in our business. Approximately 100 of these individuals devote all of their time performing management and operating duties for us. We reimburse EPCO for 100% of the costs it incurs to employ these individuals. The remaining approximate 1,300 personnel are part of EPCO’s shared service organization and spend all or a portion of their time engaged in our business. The cost for their services is reimbursed to EPCO and is generally based on the percentage of time such employees perform services on our behalf during the year. For additional information regarding the administrative services agreement and our relationship with EPCO, see Note 15 of the Notes to Financial Statements included under Item 8 of this annual report.

Available Information

     We electronically file certain documents with the U.S. Securities and Exchange Commission (“SEC”). We file annual reports on Form
10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. From time-to-time, we may also file registration statements and related documents in connection with equity or debt

offerings. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website at www.sec.gov that contains reports and other information regarding registrants that file electronically with the SEC.

     We provide electronic access to our periodic and current reports on our Internet website, www.deplp.com. These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC. You may also contact our investor relations department at (866) 230-0745 for paper copies of these reports free of charge.

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.

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.

     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 2005 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. In 2007, the NYMEX daily settlement price for natural gas ranged from a high of $8.64 per MMBtu to a low of $5.38 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:

	§		the level of domestic production and consumer product demand;
	§		the availability of imported natural gas;
	§		actions taken by foreign natural gas producing nations;
	§		the availability of transportation systems with adequate capacity;
	§		the availability of competitive fuels;

	§		fluctuating and seasonal demand for natural gas and NGLs;
	§		the impact of conservation efforts;
	§		the extent of governmental regulation and taxation of production; and
	§		the overall economic environment.

     We are indirectly exposed to natural gas and NGL commodity price risk. An increase in natural gas prices or a decrease in NGL prices could result in a decrease in the volume of NGLs fractionated by EPO’s Shoup and Armstrong fractionators, which would result in a decrease in gross operating margin for the DEP South Texas NGL Pipeline.

A decrease in demand for natural gas, 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, 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:

	§		Ethane. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. If natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls (and, therefore, the demand for ethane by NGL producers falls), it may be more profitable for natural gas producers to leave the ethane in the natural gas stream to be burned as fuel than to extract the ethane from the mixed NGL stream for sale as an ethylene feedstock.
	§		Propylene. Propylene is sold to petrochemical companies for a variety of uses, principally for the production of polypropylene. Propylene is subject to rapid and material price fluctuations. Any downturn in the domestic or international economy could cause reduced demand for, and an oversupply of propylene, which could cause a reduction in the volumes of propylene that we transport.

Any decrease in supplies of natural gas could adversely affect our business and operating results. Our success depends on our ability to obtain access to new sources of natural gas from both domestic production and LNG terminals, which sources are dependent on factors beyond our control.

     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 successful drilling activity near our pipelines;
	§		our ability to compete for these supplies;
	§		our ability to connect our pipelines to the suppliers;

	§		the successful completion of new liquefied natural gas (“LNG”) facilities near our pipelines; and
	§		our gas quality requirements.

     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 2005, 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 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. Twelve LNG projects have been approved by the FERC to be constructed in the Gulf Coast region and an additional two 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 and NGL 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 and fractionation facilities such as those serving EPO 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 or NGLs, then the volumes of NGLs transported gathered on our DEP South Texas NGL Pipeline System; natural gas gathered on our Acadian Gas System and other pipeline systems in the future could be less than we anticipate. A decline in the volumes of natural gas or NGLs 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:

	§		geographic proximity to the production;
	§		costs of connection;
	§		available capacity;
	§		rates; and
	§		access to markets.

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

     As of December 31, 2007, we had $200.0 million of indebtedness outstanding under our credit agreement and the ability to borrow up to an additional $100.0 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 obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
	§		covenants contained in our existing and future credit and debt arrangements require us to meet certain financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
	§		we may need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operation, future business opportunities and distributions to unitholders; and
	§		our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

     Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which may 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 may 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.

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

     We have exposure to increases in interest rates. As of December 31, 2007, we effectively had $25.0 million of consolidated variable-rate debt. As a result, our results of operations, cash flows and financial condition could be 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.

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 may 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 may 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 would likely be interested in purchasing or acquiring. 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 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:

	§		make distributions if any default or event of default occurs;
	§		incur additional indebtedness or guarantee other indebtedness;
	§		grant liens or make certain negative pledges;
	§		make certain loans or investments;
	§		make any material change to the nature of our business, including consolidations, liquidations and dissolutions; or
	§		enter into a merger, consolidation, sale and leaseback transaction or sale of assets.

     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. Furthermore, our credit agreement could limit our ability to make distributions upon the occurrence of the following events, among others:

	§		failure to pay any principal, interest, fees, expenses or other amounts when due;
	§		failure of any representation or warranty to be true and correct in any material respect;
	§		failure to perform or otherwise comply with the covenants in the credit agreement;
	§		failure to pay any other material debt;
	§		a bankruptcy or insolvency event involving us, our general partner or any of our subsidiaries;
	§		the entry of, and failure to pay, one or more adverse judgments in excess of a specified amount against which enforcement proceedings are brought or that are not stayed pending appeal;
	§		a change in control of us;
	§		a judgment default or a default under any material agreement if such default could have a material adverse effect on us; and
	§		the occurrence of certain events with respect to employee benefit plans subject to ERISA.

     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.

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.

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:

§		difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments;
§		establishing the internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002;
§		managing relationships with new joint venture partners with whom we have not previously partnered;
§		inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and
§		diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

     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.

Because our general partner does not own incentive distribution rights in our distributions, we may elect to acquire or build energy infrastructure assets that have a lower expected return on investment than a similarly situated publicly traded energy partnership whose partner owns incentive distribution rights.

      Duncan Energy was formed in part to support the growth objectives of EPO. EPO, the owner of our general partner, elected to forgo incentive distribution rights with respect to our distributions for the purpose of reducing our expected long-term cost of equity capital. This should allow us to acquire or build energy infrastructure assets with lower expected returns on investment that should still be accretive on a per unit basis. Such expected returns on investment may not be considered economically viable by other similarly situated publicly traded partnerships whose general partner owns incentive distribution rights, including Enterprise Products Partners. In addition, we may elect to participate in capital projects with Enterprise Products Partners and/or TEPPCO, whereby our expected return on investment may be lower than that of Enterprise Products Partners and/or TEPPCO, yet is still ultimately expected to be accretive on a per unit basis for our common units. Should the returns and cash flow from operations from such acquisitions or capital projects not materialize as expected, we may not be able to support our cash distribution rate at current levels or increase our cash distribution rate to partners in the future.

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 EPO 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:

	§		mistaken assumptions about volumes, revenues and costs, including synergies;
	§		an inability to integrate successfully the businesses we acquire;
	§		a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;
	§		a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;
	§		the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

	§		an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
	§		limitations on rights to indemnity from the seller;
	§		mistaken assumptions about the overall costs of equity or debt;
	§		the diversion of management’s and employees’ attention from other business concerns;
	§		unforeseen difficulties operating in new product areas or new geographic areas; and
	§		customer or key employee losses at the acquired businesses.

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

We depend in large part on EPO 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 EPO and its subsidiaries relating to transportation and storage services and leases. Our cash flows and financial condition depend in large part on the continued success of EPO 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 EPO. EPO has no obligation to produce any volumes at these facilities. If anticipated volumes are not processed by EPO at these facilities, our estimated revenues on this system will be reduced.

     Any adverse changes in the business of EPO, due to market conditions, sales of assets or otherwise, or the failure of EPO 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 EPO.

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 by the nationally recognized debt rating agencies. 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 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 EPO 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 EPCO and Enterprise Products Partners, the indirect owner of our general partner, have significant indebtedness outstanding and are dependent principally on the cash distributions from their 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 EPCO, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of EPCO 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. 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.

     We cannot assure you that our construction projects 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:

§

we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits;

	§		we will not receive any material increases in revenues until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;
	§		we may construct facilities to capture anticipated future growth in production or demand in a region in which such growth does not materialize;
	§		since we are not engaged in the exploration for and development of natural gas reserves, we may not have access to third-party estimates of reserves in an area prior to our constructing facilities in the area. As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate;
	§		where we do rely on third-party estimates of reserves in making a decision to construct facilities, these estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves; and
	§		we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

     The occurrence 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 NGA. Pursuant to the NGA, we are required to offer those services on an open and nondiscriminatory basis at a fair and equitable rate. Such FERC-regulated NGA 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 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 was appealed to the United States Court of Appeals for the District of Columbia Circuit. On May 29, 2007, the Court of Appeals issued its order upholding the FERC policy providing an income tax allowance for any “actual or potential income tax liability” incurred by the respective partners of a limited partnership and the application of the policy in the case before the Court.

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.

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.

We depend on EPO 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, 2007 and 2006, EPO and its affiliates accounted for approximately 9% and 13% of

our total consolidated revenues, respectively. 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 EPO; there are only two customers on our Lou-Tex Propylene Pipeline; there is only one customer on our Sabine Propylene Pipeline; and there is only one shipper on the pipeline held by Evangeline. 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 EPO 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 key 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.

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 and its affiliates, EPO and EPCO and its 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 and its affiliates, EPO and 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, EPO 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, EPO, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, then EPO will have the first right to pursue such opportunity for itself or, in its sole discretion, to affirmatively direct the opportunity to us. If EPO 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 EPO 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.

     As of December 31, 2007, EPO directly owns a 2% general partner interest and approximately 26.4% of our outstanding common units 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. These potential conflicts include, among others, the following situations:

	§		Enterprise Products Partners, EPCO and their affiliates may engage in substantial competition with us on the terms set forth in an amended and restated administrative services agreement.
	§		Neither our partnership agreement nor any other agreement requires EPCO, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO or their affiliates (other than our general partner) to pursue a business strategy that favors us. Directors and officers of EPCO and the general partners of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO and their affiliates have a fiduciary duty to make decisions in the best interest of their shareholders or unitholders, which may be contrary to our interests.
	§		Our general partner is allowed to take into account the interests of parties other than us, such as EPCO, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO and their affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
	§		Some of the officers of EPCO who provide services to us also may devote significant time to the business of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO, and will be compensated by EPCO for such services.
	§		Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.
	§		Our general partner determines the amount and timing of asset purchases and sales, operating expenditures, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.
	§		Our general partner determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us.
	§		EPO or TEPPCO may propose to contribute additional assets to us and, in making such proposal, the directors of those entities have a fiduciary duty to their unitholders and not to our unitholders.
	§		Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
	§		Our general partner intends to limit its liability regarding our contractual obligations.
	§		Our general partner may exercise its rights to call and purchase all of our common units if, at any

			time, it and its affiliates own 80% or more of the outstanding common units.
	§		Our general partner controls the enforcement of obligations owed to us by it and its affiliates, including the administrative services agreement.
	§		Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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

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 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 EPO has the power to appoint and remove our directors and management.

     Because EPO 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 EPO 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:

	§		the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and
	§		the highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed.

     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 February 1, 2008, 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:

	§		permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its rights to vote or transfer our common units it owns, its registration rights and the determination of whether to consent to any merger or consolidation of the partnership, or amendment to the partnership agreement;
	§		provides in the absence of bad faith by the Audit, Conflicts and Governance Committee or our general partner, the resolution, action or terms made, taken or provided in connection with a 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;
	§		provides the general partner shall not be liable to the partnership or any partner for its good faith reliance on the provisions of the partnership agreement to the extent it has duties, including fiduciary duties, and liabilities at law or in equity;
	§		generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the board of directors of our general partner must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us;
	§		provides that it shall be presumed that the resolution of any conflicts of interest by our general partner or the audit, conflicts and governance committee was not made in bad faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting

			such proceeding will have the burden of overcoming such presumption; and
	§		provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

     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 a limited 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:

	§		the ownership interest of unitholders immediately prior to the issuance will decrease;
	§		the amount of cash available for distributions on each common unit may decrease;
	§		the relative voting strength of each previously outstanding common unit may be diminished;
	§		the ratio of taxable income to distributions may increase; and
	§		the market price of our common units may decline.

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 certain 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 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. The payment of these amounts, including allocated overhead, to EPCO and its affiliates could adversely affect our ability to make distributions to our unitholders. EPCO has sole discretion to determine the amount of these expenses. In addition, EPCO and its affiliates may provide other services to us for which we will be charged fees as determined by EPCO.

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:

	§		we were conducting business in a state, but had not complied with that particular state’s partnership statute; or
	§		unitholders’ right to act with other unitholders to remove or replace our general partner, to approve

some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.

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 EPO 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.

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 could generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits could flow through to unitholders. Because a tax could be imposed upon us as a corporation, our cash available for distribution to our common unitholders could be substantially reduced. Thus, treatment of us as a corporation could 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 are subject to a newly revised Texas franchise tax (the “Revised Texas Franchise 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 Revised Texas Franchise Tax is 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 could be reduced.

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

     The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

     We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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 whether or not they 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 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 non-U.S. 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), other retirement plans and non-U.S. 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 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 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.

     None.

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 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 underreport 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. Grynberg has appealed the matter.

     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.

     None.

PART II

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

     We completed our initial public offering on February 5, 2007. Our common units are listed on the NYSE under the ticker symbol “DEP.” As of February 1, 2008, there were approximately 30 unitholders of record of our common units. The following table presents the high and low sales prices for our common units during the periods indicated (as reported by the NYSE Composite Transaction Tape) and the amount, record date and payment date of the quarterly cash distributions we paid on each of our common units.

										Cash Distribution History
		Price Ranges								Per				Record				Payment
2007		High				Low				Unit				Date				Date
1st Quarter (1)		$	27.30			$	22.10			$	0.2440			April 30, 2007				May 9, 2007
2nd Quarter			29.55				24.80				0.4000			July 31, 2007				August 8, 2007
3rd Quarter			29.39				20.25				0.4100			October 31, 2007				November 7, 2007
4th Quarter			25.20				20.51				0.4100			January 31, 2008				February 7, 2008

     The quarterly cash distributions per unit shown in the table above correspond to cash flows for the quarters indicated. The actual cash distributions (i.e., the payments made to our partners) occur within 45 days after the end of such quarter. We expect to fund our quarterly cash distributions to partners primarily

with cash provided by operating activities. For additional information regarding our cash flows from operating activities, see “Liquidity and Capital Resources” included under Item 7 of this annual report. Although the payment of cash distributions is not guaranteed, we expect to continue to pay comparable cash distributions in the future.

     We had no sales of unregistered securities during the eleven months ended December 31, 2007 and we have no common units authorized for issuance under an equity compensation plan. We did not repurchase any of our common units during the eleven months ended December 31, 2007.

Item 6. Selected Financial Data.

     The following table presents selected historical consolidated financial data of Duncan Energy Partners and combined financial data of Duncan Energy Partners Predecessor. This information has been derived from our audited financial statements and should be read in conjunction with such statements included under Item 8 of this annual report. As presented in the table, amounts are in thousands (except per unit data).

		Duncan Energy
		Partners					Duncan Energy Partners Predecessor
		For the Eleven					For the One
		Months Ended					Month Ended
		December 31,					January 31,				For the Year Ended December 31,
		2007					2007				2006				2005				2004				2003
Operating Results Data:
Revenues		$	797,044				$	66,674			$	924,478			$	953,397			$	748,931			$	668,234
Income from continuing operations (1)		$	19,232				$	5,035			$	55,328			$	39,669			$	58,124			$	52,454
Net income		$	19,232				$	5,035			$	55,337			$	39,087			$	58,124			$	52,454
Basic and diluted net income per unit		$	0.930					n/a				n/a				n/a				n/a				n/a
Cash distributions per common unit (2)		$	1.464					n/a				n/a				n/a				n/a				n/a
Financial position data (at period end):
Total assets (3)		$	982,406				$	810,847			$	804,112			$	642,840			$	590,487			$	581,816
Long-term debt (4)		$	200,000					n/a				n/a				n/a				n/a				n/a
Owners’ net investment — Predecessor			n/a				$	739,372			$	725,797			$	527,767			$	509,719			$	524,127
Partners’ equity		$	316,775					n/a				n/a				n/a				n/a				n/a
Total common units outstanding			20,302					n/a				n/a				n/a				n/a				n/a

     Information regarding our consolidated results of operations and liquidity and capital resources can be found under Item 7 of this annual report. The historical combined financial information of Duncan Energy Partners Predecessor reflects the assets, liabilities and operations contributed to us by EPO at the closing of our initial public offering on February 5, 2007 (effective February 1, 2007 for financial accounting and reporting purposes). Our historical consolidated financial information differs from the combined financial information of the Predecessor due to a variety of factors, including the following:

	§		Partial ownership of operating assets;
	§		No historical results for our NGL Pipelines & Services Segment;
	§		Increase in outstanding indebtedness;
	§		Increased storage fees;

	§		Special allocation of storage well and operational measurement gains and losses;
	§		Decrease in propylene transportation rates; and
	§		Additional general and administrative expenses.

     For additional information regarding these factors, see “Basis of Financial Statement Presentation” included under Item 7 of this annual report.

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

For the years ended December 31, 2007, 2006 and 2005.

     The following information should be read in conjunction with our financial statements and accompanying notes included under Item 8 of this annual report. Our discussion and analysis includes the following:

	§		Cautionary Note Regarding Forward-Looking Statements.
	§		Significant Relationships Referenced in this Discussion and Analysis.
	§		Overview of Business.
	§		Recent Developments — Discusses significant developments since our initial public offering in February 2007.
	§		Basis of Financial Statement Presentation.
	§		Results of Operations — Discusses material year-to-year variances in our Statements of Consolidated/Combined Operations.
	§		Liquidity and Capital Resources — Addresses available sources of liquidity and capital resources and includes a discussion of our capital spending program.
	§		Critical Accounting Policies and Estimates.
	§		Other Items — Includes information related to contractual obligations, off-balance sheet arrangements, related party transactions, recent accounting pronouncements and similar disclosures.

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

		/d BBtus Bcf MBPD MMBbls MMBtus MMcf		= per day = billion British thermal units = billion cubic feet = thousand barrels per day = million barrels = million British thermal units = million cubic feet

     Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

Cautionary Note Regarding Forward-Looking Statements

     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,” “seek,” “goal,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” 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 materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements.

Significant Relationships Referenced in this Discussion and Analysis

     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 1, 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 prior to February 5, 2007, these terms are intended to mean the combined business and operations of Duncan Energy Partners Predecessor.

     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.

     References to “DEP GP” mean DEP Holdings, LLC, which is our general partner.

     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 LLC. Enterprise Products Partners is a publicly traded partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”

     References to “EPO” mean our Parent, which is Enterprise Products Operating LLC and its consolidated subsidiaries. EPO owns a 100% interest in the Partnership’s general partner and is a significant owner of the Partnership’s common units.

     References to “EPGP” mean Enterprise Products GP, LLC, the general partner of Enterprise Products Partners.

     References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.”

     References to “TEPPCO GP” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings L.P.

     References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the registered limited partnership interests of which are listed on the NYSE under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity.

     References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., which owns EPGP, TEPPCO GP and limited partner interests in Enterprise Products Partners and TEPPCO. Enterprise GP Holdings is a publicly traded partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.”

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

     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 Mr. Dan L. Duncan, the Co-Chairman and controlling shareholder of EPCO.

Overview of Business

     Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the 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 and to support growth objectives of EPO. We are owned 98% by our limited partners and 2% by our general partner, DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is responsible for managing all of our operations and activities. EPCO provides all employees and certain administrative services for us.

     On February 5, 2007, we completed our initial public offering of 14,950,000 common units, which generated net proceeds of $290.5 million. We distributed $260.6 million of such net proceeds, plus $198.9 million in borrowings under our credit facility along with a final amount of 5,351,571 of our common units to EPO as consideration for a 66% equity ownership interest in each of the following businesses (effective February 1, 2007):

	§		Mont Belvieu Caverns owns and operates salt dome caverns and a brine system located in Mont Belvieu, Texas.
	§		Acadian Gas gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of high-pressure transmission pipelines and lateral and gathering lines with an aggregate throughput capacity of one billion cubic feet per day (the “Acadian Gas System”), including a 27-mile pipeline owned by our unconsolidated affiliate Evangeline Gas Pipeline L.P. (“Evangeline”) and a leased storage cavern with three billion cubic feet of storage capacity.
	§		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 the DEP South Texas NGL Pipeline System, which is a 286-mile NGL pipeline extending from Corpus Christi, Texas to Mont Belvieu, Texas that commenced operations in January 2007.

     EPO operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years prior to its contribution of equity interests in such entities to us. On February 5, 2007, DEP Operating Partnership directly or indirectly assumed these responsibilities.

     EPO may contribute or sell other equity interests in its subsidiaries or other of its or its subsidiaries’ assets to the Partnership and use the proceeds it receives to fund its capital spending program. However, EPO has no obligation or commitment to make such contributions or sales to the Partnership.

     In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with the Partnership in accordance with the existing sharing ratio of 66% funded by the Partnership and 34% funded by EPO. See our discussion of “Financing Activities” beginning on page 55 of this annual report for information regarding recent cash contributions made by EPO in connection with the Omnibus Agreement and Mont Belvieu Caverns’ limited liability company agreement.

Recent Developments

     The following information highlights significant developments since our initial public offering in February 2007 through the date of this quarterly filing:

§

In January 2008, the board of directors of our general partner declared a quarterly cash distribution rate of $0.41 per common unit. This distribution was paid on February 7, 2008 to unitholders of record on January 31, 2008. The following table summarizes our quarterly cash distributions since our initial public offering:

		Cash Distribution History
		Distribution				Record		Payment
		per Unit				Date		Date
1st Quarter 2007 (1)		$	0.244			Apr. 30, 2007		May 9, 2007
2nd Quarter 2007		$	0.400			Jul. 31, 2007		Aug. 8, 2007
3rd Quarter 2007		$	0.410			Oct. 31, 2007		Nov. 7, 2007
4th Quarter 2007		$	0.410			Jan. 31, 2008		Feb. 7, 2008

§

In July 2007, the board of directors of our general partner announced changes to its senior management team that became effective August 1, 2007. The board of directors of our general partner elected W. Randall Fowler as executive vice president and chief financial officer, Mr. Fowler was promoted to fill the position vacated by Michael A. Creel, who became the president and chief executive officer of Enterprise Products Partners.

Basis of Financial Statement Presentation

     The historical combined financial information and operating data included in this discussion and analysis pertaining to periods prior to our initial public offering reflects the assets, liabilities and operations contributed to us by EPO at the closing of our initial public offering on February 5, 2007 (effective February 1, 2007 for financial accounting and reporting purposes). We refer to these historical assets, liabilities and operations as the assets, liabilities and operations of Duncan Energy Partners Predecessor.

     Our discussion of amounts attributable to Duncan Energy Partners Predecessor reflects EPO’s historical ownership of these assets, liabilities and operations. The principal business entities included in the historical combined financial statements of Duncan Energy Partners Predecessor are (on a 100% basis): Mont Belvieu Caverns; Acadian Gas; Lou-Tex Propylene, including its general partner; Sabine Propylene, including its general partner; and South Texas NGL Pipelines. EPO contributed a 66% equity interest in each of these five entities to us on February 5, 2007. EPO retained the remaining 34% equity interests in each of these subsidiaries.

     Our discussion of the financial condition and results of operations for Duncan Energy Partners Predecessor should be read in conjunction with the financial statements and Notes to Financial Statements of Duncan Energy Partners included under Item 8 of this annual report. Since our initial public offering, our historical results of operations have differed from those of our Predecessor due to a variety of factors, including the following:

     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 EPO continue to own the remaining 34%. Accordingly, our discussion of results prior to February 2007 reflects 100% of the results of operations of these assets. We recognize EPO’s ownership of our operating subsidiaries as “Parent interest in subsidiaries” in our financial statements.

     No Historical Results for Our NGL Pipelines & Services Segment. Our discussion of historical results prior to January 2007 does not reflect any operations related to our DEP South Texas NGL Pipeline System, which did not commence operations until January 2007.

     Increase in Outstanding Indebtedness. Prior to our initial public offering, we did not have any consolidated indebtedness and, therefore, we did not have 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 EPO in connection with its contribution of certain equity interests to us.

     Increased Storage Fees. As a result of contracts executed in connection with our initial public offering, we increased certain storage fees charged to EPO 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. These rates are now market-based. See “Relationship with EPO” under Note 15 of the Notes to Financial Statements for additional information regarding revenues recorded by the Predecessor versus those we recorded since our initial public offering.

     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 connection with storage agreements entered into between EPO and Mont Belvieu Caverns effective concurrently with the closing of our initial public offering, EPO agreed to assume 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. Beginning February 2007, the Mont Belvieu Caverns’ limited liability company agreement allocates to EPO 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, EPO 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 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 flows 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. Beginning February 2007, the transportation fees we received from customers utilizing our Lou-Tex Propylene and Sabine Propylene Pipelines were lower than those we realized in prior periods. Historically, EPO was the shipper of record on these pipelines, and we charged it the maximum tariff rate for using these assets. EPO then contracted with third parties to ship volumes on these pipelines under product exchange agreements. In general, the revenues recognized by EPO in connection with these exchange agreements were lower than the maximum tariff rate it paid us. In connection with our initial public offering, EPO 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 fees we received from EPO prior to February 2007. See “Relationship with

EPO” under Note 15 of the Notes to Financial Statements for additional information regarding revenues recorded by the Predecessor versus those we recorded since our initial public offering.

     Additional General and Administrative Expenses. We incur additional general and administrative costs 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. See “Relationship with EPCO” under Note 15 of the Notes to Financial Statements for additional information regarding the administrative services agreement.

Results of Operations

     We are currently engaged in the business of gathering, transporting, marketing and storing natural gas and transporting and storing NGLs and petrochemicals. We have four reportable business segments:

	§		NGL & Petrochemical Storage Services;
	§		Onshore Natural Gas Pipelines & Services;
	§		Petrochemical Pipeline Services; and
	§		NGL Pipelines & 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. In January 2008, we renamed our Natural Gas Pipelines & Services segment to be Onshore Natural Gas Pipelines & Services. Likewise, we changed the name of the NGL Pipeline Services segment to NGL Pipelines & Services. Apart from these name changes, no other revisions were made to these segments.

     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 financial 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 segment gross operating margin as consolidated 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. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation.

     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’s operations complement those of Acadian Gas. As circumstances dictate, we may increase our ownership interest in Evangeline or make other equity method investments.

  Selected Volumetric Data

     The following table presents selected average pipeline throughput volumes for the periods indicated:

		Duncan Energy
		Partners					Duncan Energy Partners Predecessor
		For the Eleven					For the One
		Months Ended					Month Ended				For the Year Ended
		December 31,					January 31,				December 31,
		2007					2007				2006				2005
Onshore Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (BBtus/d)
Acadian Gas System transportation volumes			416					420				434				323
Acadian Gas System sales volumes			310					281				325				317
Total natural gas throughput volumes			726					701				759				640
Petrochemical Pipeline Services, net:
Propylene throughput volumes (MBPD)
Lou-Tex Propylene Pipeline			25					24				27				23
Sabine Propylene Pipeline			12					13				10				10
Total propylene throughput volumes			37					37				37				33
NGL Pipelines & Services, net:
NGL throughput volumes (MBPD)
DEP South Texas NGL Pipeline System			73					67				—				—

  Comparison of Results of Operations

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

		Duncan Energy
		Partners					Duncan Energy Partners Predecessor
		For the Eleven					For the One Month
		Months Ended					Ended				For the Year Ended
		December 31,					January 31,				December 31,
		2007					2007				2006				2005
Revenues		$	797,044				$	66,674			$	924,478			$	953,397
Operating Costs and expenses			745,026					61,187				867,060				909,044
General and administrative			4,022					477				3,486				4,483
Equity in income of unconsolidated affiliates			157					25				958				331
Operating income			48,153					5,035				54,890				40,201
Parent interest in income of subsidiaries (1)			19,973					—				—				—
Net income			19,232					5,035				55,337				39,087

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

		Duncan Energy
		Partners					Duncan Energy Partners Predecessor
		For the Eleven					For the One Month
		Months Ended					Ended				For the Year Ended
		December 31,					January 31,				December 31,
		2007					2007				2006				2005
NGL & Petrochemical Storage Services		$	36,419				$	1,770			$	23,940			$	16,636
Onshore Natural Gas Pipelines & Services			11,133					1,605				20,144				18,939
Petrochemical Pipeline Services			11,649					2,700				35,710				28,567
NGL Pipelines & Services			19,479					1,646				—				—
Total segment gross operating margin		$	78,680				$	7,721			$	79,794			$	64,142

     For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP net income, see “Other Items — Non-GAAP Reconciliations” within this Item 7. For additional information regarding our business segments, see Note 14 of the Notes to Financial Statements included under Item 8 of this annual report.

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

		Duncan Energy
		Partners					Duncan Energy Partners Predecessor
		For the Eleven					For the One
		Months Ended					Month Ended				For the Year Ended December 31,
		December 31, 2007					January 31, 2007				2006				2005
NGL & Petrochemical Storage Services		$	66,315				$	5,164			$	59,144			$	52,838
Onshore Natural Gas Pipelines & Services			696,134					56,769				826,247				866,693
Petrochemical Pipeline Services			14,401					2,990				39,087				33,866
NGL Pipelines & Services			20,194					1,751				—				—
Total revenues		$	797,044				$	66,674			$	924,478			$	953,397

  Comparison of Year Ended December 31, 2007 with Year End December 31, 2006

     As described under “Basis of Financial Statement Presentation” within this Item 7, there are several factors that affect the comparability of our current results with those of Duncan Energy Partners Predecessor. Amounts referenced below for the 2007 period reflect the combined results of Duncan Energy Partners Predecessor for January 2007 and the consolidated results of the Partnership for the eleven months ended December 31, 2007. Likewise, amounts referenced below for the year ended December 31, 2006 reflect the combined results of Duncan Energy Partners Predecessor.

     Revenues for 2007 were $863.7 million compared to $924.5 million for 2006. The $60.8 million decrease in revenues year-to-year is primarily due to lower revenues associated with our natural gas marketing activities. Revenues from the sale of natural gas decreased $72.6 million year-to-year primarily due to lower natural gas sales volumes and prices. Revenues from propylene transportation decreased $21.7 million year-to-year primarily due to lower transportation fees in 2007 relative to 2006. Revenues from our NGL and petrochemical storage business increased $12.3 million year-to-year primarily due to higher storage fee revenues from increased rates. In addition, revenues for 2007 include $21.9 million from the DEP South Texas NGL Pipeline, which became operational in January 2007.

     Operating costs and expenses were $806.2 million for 2007 compared to $867.1 million for 2006. This $60.9 million year-to-year decrease in 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 $71.6 million year-to-year as a result of a decrease in volumes and natural gas prices.

General and administrative costs increased $1.0 million year-to-year. Equity earnings from Evangeline decreased $0.8 million year-to-year.

     Changes in our revenues and costs and expenses year-to-year are explained in part by changes in energy commodity prices. In general, lower natural gas prices result in a decrease in our revenues attributable to the sale of natural gas by Acadian Gas; however, these lower commodity prices also decrease the associated cost of sales as purchase prices decline. The market price of natural gas (as measured at Henry Hub) averaged $6.86 per MMBtu for 2007 versus $7.24 per MMBtu for 2006.

     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.

     Operating income for 2007 was $53.2 million compared to $54.9 million for 2006. Collectively, the aforementioned changes in revenues, costs and expense and equity earnings contributed to the $1.7 million year-to-year decrease in operating income. Interest expense for 2007 includes $9.3 million attributable to debt that was incurred at the time of our initial public offering. In addition, net income for 2007 includes $20.0 million of expense for “Parent interest in income of subsidiaries.”

     As a result of the items noted in the previous paragraphs, our net income decreased $31.0 million year-to-year to $24.3 million in 2007 compared to $55.3 million in 2006. Net income for 2006 includes the recognition of non-cash amounts related to the cumulative effect of change in accounting principle. For additional information regarding the cumulative effect of change in accounting principle we recorded in 2006, 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 $38.2 million for 2007 compared to $23.9 million for 2006. Revenues increased $12.3 million year-to-year primarily due to higher excess storage and throughput fees and brine production revenues. Operating costs and expenses decreased $2.0 million year-to-year primarily due to reduced measurement losses, which were partially offset by higher maintenance and integrity management expenses during 2007 relative to 2006.

     Storage fee revenues for 2007 were $11.0 million higher than 2006 primarily as a result of contracts executed in connection with our initial public offering, which increased certain storage fees charged to EPO. Historically, such intercompany charges had been below market and eliminated in the consolidated revenues and costs and expenses of Enterprise Products Partners. The changes in these contracts resulted in a $9.2 million increase in storage revenues for 2007 compared to 2006. In addition, our storage revenues increased $1.8 million year-to-year primarily due to higher contracted storage volumes and fees, which increased reservation, excess storage and throughput revenues.

     Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $12.7 million for 2007 compared to $20.1 million for 2006, a $7.4 million decrease year-to-year. Natural gas throughput volumes decreased to 724 BBtu/d during 2007 from 759 BBtu/d during 2006. Segment gross operating margin decreased $2.6 million year-to-year attributable to our collection of a contingent asset during 2006. The remainder of the year-to-year decrease in segment gross operating margin is primarily due to (i) lower natural gas sales margins, (ii) lower natural gas sales volumes and (iii) higher repair and maintenance costs during 2007 compared to 2006. Equity earnings from our investment in Evangeline decreased $0.8 million year-to-year due to lower natural gas sales margins and higher maintenance costs during 2007 relative to 2006.

     Petrochemical Pipeline Services. Gross operating margin from this business segment was $14.3 million for 2007 compared to $35.7 million for 2006. Petrochemical transportation volumes were 37 MBPD during both 2007 and 2006. Transportation revenues decreased $21.7 million year-to-year as a result of EPO assigning its third party product exchange agreements to us in connection with our initial public offering. Accordingly, the transportation fees we currently receive for use of our Lou-Tex Propylene and Sabine Propylene Pipelines are less than the fees we received from EPO prior to February 2007. Operating costs and expenses decreased $0.3 million year-to-year as a result of lower pipeline integrity expenses.

     NGL Pipelines & Services. Gross operating margin from this business segment was $21.1 million for 2007. Results for this business segment are attributable to the DEP South Texas NGL Pipeline. NGL transportation volumes on our DEP South Texas NGL Pipeline were 73 MBPD during 2007.

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

     The following discussion reflects the combined results for Duncan Energy Partners Predecessor for the years ended December 31, 2006 and 2005.

     Combined revenues for 2006 were $924.5 million compared to $953.4 million for 2005. The year-to-year decrease in combined revenues 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. General and administrative costs decreased $1.0 million year-to-year. Equity earnings from Evangeline increased $0.6 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. The Henry Hub market price of natural gas averaged $7.24 per MMBtu for 2006 versus $8.64 per MMBtu for 2005.

     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. Other expense for 2005 includes $0.5 million of accrued interest related to a potential assessment for a state sales tax dispute. The expense accrual was reversed 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 expenses for utilities and maintenance.

     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 reflecting contractual changes made to the sales agreements with our customers during 2006.

     Onshore 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 during 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 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.

   General Outlook for 2008

     Generally, the commercial activities of our assets are substantially supported by long-term contracts and have historically exhibited limited variability in demand. We believe for the most part that our assets will perform in a manner consistent with our results from operations for 2007. We continue to evaluate opportunities to acquire new assets from our affiliate EPO and from third parties which may be complementary to our existing platform of assets or provide geographic diversification. Based on current domestic and industry economic conditions,

	§		We believe demand for our NGL and petrochemical storage services, which are critical to the operations of our petrochemical and refining customers and EPO, will be consistent with 2007. We believe we may have opportunities to increase revenues at this facility through an increase in NGL imports, new contracts, higher volumes and an increase in fees.
	§		We believe that the current strength of the domestic and global economies should continue to drive increased demand for all forms of energy despite fluctuating commodity prices. The largest of our NGL customers in the ethylene and propylene industries continue to see strong demand for their products. The NGL products ethane and propane continue to be the preferred feedstocks for the ethylene industry due to the higher cost of crude oil derivatives.

Liquidity and Capital Resources

     At December 31, 2007, we had $2.2 million of unrestricted cash on hand and approximately $98.9 million of available credit under our $300 million revolving credit facility. We had $200.0 million in principal and $1.1 million of letters of credit outstanding under this credit facility at December 31, 2007. As of February 1, 2008, we had $1.1 million of letters of credit outstanding under this credit facility. Our revolving credit facility requires us to maintain certain financial and other customary covenants. We were

in compliance with the covenants of our credit facility and believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities.

     Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows and borrowings under our 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 operating cash flows, borrowings under credit facilities, cash contributions from the Parent, the issuance of additional equity and debt securities and proceeds from divestitures of ownership interests in assets to affiliates or third parties. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

    Registration Statements

     We may issue equity or debt securities to assist us in meeting our liquidity and capital spending requirements. As a result, we may file registration statements in the future with the U.S. Securities and Exchange Commission.

   Cash Flows from Operating, Investing and Financing Activities

     This discussion of our cash flows addresses the eleven-month period since our initial public offering in February 2007. Due to the factors affecting comparability of our financial statements with those of Duncan Energy Partners Predecessor (see page 46), we do not believe that a discussion of cash flow variances between the pre- and post-February 1, 2007 periods is meaningful or relevant to investors. The following table summarizes our total operating, investing and financing cash flows for the eleven months ended December 31, 2007 (dollars in thousands).

		For the Eleven
		Months Ended
		December 31,
		2007
Net cash flows provided by operating activities		$	93,716
Cash used in investing activities			173,680
Cash provided by financing activities			82,160

     See our Statements of Consolidated Cash Flows included under Item 8 of this annual report for information regarding the components of the cash flow totals presented above.

     Operating activities. Net cash flows provided by operating activities were $93.7 million for the eleven months ended December 31, 2007. These cash flows are primarily influenced by earnings and the timing of cash receipts from sales and cash payments for purchases and other expenses between periods. For information regarding our earnings, please see “Results of Operations” included within this Item 7.

     Net cash flows provided by operating activities are largely dependent on earnings from our business activities. As a result, these cash flows are exposed to certain risks. We operate predominantly in the midstream energy industry. We provide services for producers and consumers of natural gas and NGLs. The products that we store, sell or transport are principally used as fuel for residential, agricultural and commercial heating; as feedstocks in petrochemical manufacturing and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products or increased competition from other service providers or producers due to pricing differences or other reasons could have a negative impact on our earnings and thus the availability of cash from operating activities.

     Investing activities. Cash used in investing activities was $173.7 million for the eleven months ended December 31, 2007. This amount includes $177.6 million of consolidated capital expenditures for property, plant and equipment, which primarily consists of $100.2 million for Mont Belvieu storage well optimization projects, $18.4 million for Mont Belvieu brine production and storage reservoir projects, and $50.4 million for Phases I and II of our DEP South Texas NGL Pipeline System. Based on information currently available, we estimate our capital spending for 2008 will approximate $85.3 million, which includes $68.3 million for certain projects that are expected to be funded 100% by EPO. EPO’s funding of our forecasted capital spending is based on the Omnibus Agreement and provisions in the Mont Belvieu Caverns’ limited liability company agreement. See the following section titled “Financing activities” for information regarding these agreements, including certain contributions EPO made in December 2007 to fund our consolidated capital spending program.

     Our forecast of consolidated capital expenditures is based on our strategic operating and growth plans, which are dependent upon our ability to generate the required funds from either operating cash flows or from other means, including borrowings under our debt agreement or cash contributions from Parent. Our forecast of capital expenditures may change due to factors beyond our control, such as weather related issues, changes in supplier prices, changes in our estimates or adverse economic conditions. Furthermore, our forecast may change as a result of decisions made by management at a later date. We believe our access to capital resources is sufficient to meet the demands of our current and future operating growth needs, and although we currently intend to make the forecasted expenditures discussed above, we may adjust the timing and amounts of projected expenditures in response to unexpected changes.

     In September 2007, Enterprise Texas Pipeline LLC, a wholly owned subsidiary of EPO, purchased certain parcels of land and regulatory permits from Mont Belvieu Caverns for $3.2 million. Due to common control considerations, the excess of the proceeds received from EPO over the carrying value of the assets sold was recorded as an equity contribution to Mont Belvieu Caverns. We used our $2.1 million share of the proceeds from this transaction to temporarily reduce principal outstanding under our revolving credit facility.

     Financing activities. Cash provided by financing activities was $82.2 million for the eleven months ended December 31 2007. Our initial public offering on February 5, 2007 generated net proceeds of $290.5 million from the issuance of 14,950,000 common units. We used $260.6 million of these net proceeds, along with net borrowings of $198.9 million (net of $1.1 million of debt issuance costs), to make a special cash distribution to EPO of $459.6 million. This cash payment and issuance of 5,351,571 of our common units was the combined consideration for equity interests and related construction-in-progress amounts EPO contributed to us at the time of our initial public offering.

     Our cash distributions to unitholders were $21.8 million for the eleven months ended December 31, 2007. In addition, our subsidiaries made permanent cash distributions from operating cash flow to EPO in the amount of $31.4 million during this period. Conversely, EPO made permanent cash contributions to our operating subsidiaries of $105.0 million, which includes a $48.0 million payment made in connection with the Omnibus Agreement and Mont Belvieu Caverns’ limited liability company agreement. Such contributions from EPO were primarily used to fund its share of our consolidated capital spending program.

     In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with the Partnership in accordance with the existing sharing ratio of 66% funded by the Partnership and 34% funded by EPO. Under the Omnibus Agreement, EPO agreed to make additional contributions to us as reimbursement for our 66% share of any excess project costs above (i) the $28.6 million of estimated project costs to complete the Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated project costs for additional Mont Belvieu brine production capacity and above-ground storage reservoir projects. These projects were in progress at the time of our initial public offering. In December 2007, EPO made cash contributions totaling $9.9 million to our subsidiaries in connection with the Omnibus Agreement.

     In December 2007, EPO made an additional $38.1 million cash contribution to Mont Belvieu Caverns for capital expenditures in which the Partnership is not a participant. This contribution was in

accordance with provisions of the Mont Belvieu Caverns’ limited liability company agreement, which states that when the Partnership elects to not participate in certain projects, then EPO is responsible for funding 100% of such projects. To the extent such non-participated projects generate incremental earnings for Mont Belvieu Caverns in the future, the sharing ratio for Mont Belvieu Caverns will be adjusted to allocate such incremental cash flows to EPO. Under the terms of the agreement, the Partnership may elect to reacquire for consideration a 66% share of these projects at a later date.

     Mont Belvieu Caverns distributed to us the $48.0 million in cash contributions it received from EPO with respect to the foregoing contributions made under the Omnibus Agreement ($9.9 million) and Mont Belvieu Caverns’ limited liability company agreement ($38.1 million). We, in turn, used such proceeds to reduce amounts outstanding under our revolving credit facility.

     We expect additional contributions from EPO under the Omnibus Agreement and Mont Belvieu Caverns limited liability company agreement in 2008.

Critical Accounting Policies and Estimates

     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 currently 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 into 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. Examples of such circumstances include:

	§		changes in laws and regulations that limit the estimated economic life of an asset;
	§		changes in technology that render an asset obsolete;
	§		changes in expected salvage values; or
	§		changes in the forecast life of applicable resource basins, if any.

     At December 31, 2007 and 2006, the net book value of our property, plant and equipment was $877.5 million and $707.6 million, respectively. We recorded $28.0 million, $21.4 million and $19.2 million in depreciation expense for the years ended December 31, 2007, 2006 and 2005, 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 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 equity method investment 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, 2007 and 2006, the carrying value of our intangible asset portfolio was $6.7 million and $7.0 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

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, 2007 and 2006, our imbalance receivables were $0.9 million and $2.6 million, respectively, and are reflected as a component of “Accounts receivable — trade” on our balance sheets. At December 31, 2007 and 2006, our imbalance payable was $0.4 million and $0.5 million respectively, and is reflected as a component of “Accrued products payables” on our balance sheets.

Other Items

    Contractual Obligations

     The following table summarizes our significant contractual obligations at December 31, 2007 (dollars in thousands). For additional information regarding these obligations, see Note 17 of the Notes to the Financial Statements included under Item 8 of this annual report.

		Payment or Settlement due by Period
						Less than				1-3				3-5				More than
Contractual Obligations(1)		Total				1 year				years				years				5 years
Scheduled maturities of long term debt (2)		$	200,000			$	—			$	—			$	200,000			$	—
Estimated cash interest payments (3)		$	37,547			$	11,765			$	23,705			$	2,077			$	—
Operating lease obligations (4)		$	2,719			$	553			$	962			$	976			$	228
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas (5)		$	685,600			$	137,345			$	273,940			$	274,315			$	—
Other		$	42			$	42			$	—			$	—			$	—
Underlying major volume commitments:
Natural gas (in BBtus)			91,350				18,300				36,500				36,550				—
Capital expenditure commitments (6)		$	20,731			$	20,731			$	—			$	—			$	—
Other long-term liabilities (7)		$	3,937			$	—			$	3,082			$	—			$	855
Total		$	950,576			$	170,436			$	301,689			$	477,368			$	1,083

    Off-Balance Sheet Arrangements

     At December 31, 2007, Evangeline’s debt obligations consisted of (i) $13.2 million in principal amount of 9.90% fixed rate Series B senior secured notes due December 2010 and (ii) a $7.5 million subordinated note payable. See Note 11 of the Notes to Financial Statements for additional information regarding this debt obligation.

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

    Summary of Related Party Transactions

     We have extensive and ongoing business relationships with EPCO, EPO and other related party affiliates. See Item 13 of this annual report for a discussion of these relationships.

   Non-GAAP Reconciliations

     A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and further to GAAP net income is presented in the following table (dollars in thousands):

		Duncan Energy
		Partners					Duncan Energy Partners Predecessor
		For the Eleven					For the One
		Months Ended					Month Ended				For the Year Ended
		December 31,					January 31,				December 31,
		2007					2007				2006				2005
Total non-GAAP segment gross operating margin		$	78,680				$	7,721			$	79,794			$	64,142
Adjustments to reconcile total non-GAAP segment gross operating to GAAP net income:
Depreciation, amortization and accretion in operating costs and expenses			(26,524	)				(2,209	)			(21,443	)			(19,453	)
Gain (loss) on sale of assets in operating costs and expenses			19					—				25				(5	)
General and administrative costs			(4,022	)				(477	)			(3,486	)			(4,483	)
GAAP operating income			48,153					5,035				54,890				40,201
Other income (expense), net			(8,641	)				—				459				(532	)
Provision for income taxes			(307	)				—				(21	)			—
Parent interest in subsidiaries			(19,973	)				—				—				—
Cumulative effect of accounting changes			—					—				9				(582	)
GAAP net income		$	19,232				$	5,035			$	55,337			$	39,087

    Cumulative Effect of Changes in Accounting Principles

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

	§		We recognized, as a benefit, a cumulative effect of a change in accounting principle of $9 thousand in 2006 based on the Statement of Financial Accounting Standards (“SFAS”) 123(R), “Share-Based Payment,” requirements 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.
	§		We recorded a $0.6 million non-cash expense related to certain asset retirement obligations in 2005 due to our implementation of Financial Accounting Standards Board (“FASB”) Interpretation 47 as of December 31, 2005.

     For additional information regarding these changes in accounting principles, see Note 6 of the Notes to Financial Statements included under Item 8 of this annual report.

    Recent Accounting Developments

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

	§		SFAS 157, “Fair Value Measurements”;
	§		SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51”;
	§		SFAS 141(R), “Business Combinations.”

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

Insurance Matters

     We participate as named insureds in EPCO’s current insurance program, which provides us with property damage, business interruption and other coverages, which are customary for the nature and scope of our operations. EPCO attempts to place all insurance coverage with carriers having ratings of “A” or higher. However, two carriers associated with the EPCO insurance program were downgraded by Standard & Poor’s during 2006. One of these carriers is currently rated at “A-” and the other, “BBB.” At present, there is no indication that these two carriers would be unable to fulfill any insuring obligation. Furthermore, we currently do not have any claims which might be affected by these carriers. EPCO continues to monitor these situations. For additional information regarding our significant risks and uncertainties due to hurricanes, see Note 18 of the Notes to Financial Statements included under Item 8 of this annual report.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

     We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e. futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions.

Interest Rate Risk Hedging Program

     As presented in the following table, Duncan Energy Partners had three interest rate swap agreements outstanding at December 31, 2007 that were accounted for as cash flow hedges.

		Number		Period Covered		Termination		Variable to		Notional
Hedged Variable Rate Debt		Of Swaps		by Swap		Date of Swap		Fixed Rate(1)		Value
Duncan Energy Partners’ Revolver, due Feb. 2011		3		Sep. 2007 to Sep. 2010		Sep. 2010		4.84% to 4.62%		$175.0 million

     In September 2007, we executed three floating-to-fixed interest rate swaps having a combined notional value of $175 million. The purpose of entering into transactions is to reduce the sensitivity of our earnings to variable interest rates charged under our revolving credit facility. We recognized a $0.2 million benefit from these swaps in interest expense during 2007, which includes ineffectiveness of $0.2 million and income of $0.4 million. In 2008, we expect to reclassify $0.7 million of accumulated other comprehensive loss that was generated by these interest rate swaps as an increase to interest expense.

     At December 31, 2007, the aggregate fair value of these interest rate swaps was a liability of $3.8 million. As cash flow hedges, any increase or decrease in fair value (to the extent effective) would be recorded into other comprehensive income and amortized into income based on the settlement period hedged. Any ineffectiveness is recorded directly into earnings as an increase in interest expense. The following table shows the effect of hypothetical price movements on the estimated fair value of Duncan Energy Partners’ interest rate swap portfolio (dollars in thousands).

						Swap Fair Value at
		Resulting				December 31,				February 12,
Scenario		Classification				2007				2008
FV assuming no change in underlying interest rates		Liability				$	3,782			$	7,749
FV assuming 10% increase in underlying interest rates		Liability					2,245				6,563
FV assuming 10% decrease in underlying interest rates		Liability					5,319				8,934

Commodity Risk Hedging Program

     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.

     Acadian Gas also 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 mark-to-market 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. Our general partner now monitors the hedging strategies associated with the physical and financial risks of Acadian Gas, approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.

     The fair value of the Acadian Gas commodity financial instrument portfolio was a negligible amount at both December 31, 2007 and 2006. We recorded losses of $0.7 million and $0.4 million for the eleven months ended December 31, 2007 and for the one month ended January 31, 2007. We also recorded losses of $0.8 million and $0.2 million for the years ended December 31, 2006 and 2005, respectively.

     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 dates 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):

						Commodity Financial Instrument Portfolio FV at
		Resulting				December 31,				December 31,				February 12,
Scenario		Classification				2006				2007				2008
FV assuming no change in underlying commodity prices		Asset				$	2			$	32			$	1
FV assuming 10% increase in underlying commodity prices		Asset (Liability)					12				(409	)			1
FV assuming 10% decrease in underlying commodity prices		Asset					12				475				1

Product purchase commitments

     Acadian Gas 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.

Item 8. Financial Statements and Supplementary Data.

DUNCAN ENERGY PARTNERS L.P.
INDEX TO FINANCIAL STATEMENTS

		Page No.
Report of Independent Registered Public Accounting Firm		64
Consolidated Balance Sheet as of December 31, 2007;  Combined Balance Sheet as of December 31, 2006		65
Statement of Consolidated Operations and Comprehensive Income for the Eleven Months Ended December 31, 2007; Statements of Combined Operations and Comprehensive Income for the Month Ended January 31, 2007 and Years Ended December 31, 2006 and 2005		66
Statement of Consolidated Cash Flows for the Eleven Months Ended December 31, 2007; Statements of Combined Cash Flows for the Month Ended January 31, 2007 and Years Ended December 31, 2006 and 2005		67
Statement of Consolidated Partners’ Equity for the Eleven Months Ended December 31, 2007; Statements of Owners’ Net Investment for the Month Ended January 31, 2007 and Years Ended December 31, 2006 and 2005		68
Notes to Financial Statements
Note 1 – Background and Basis of Financial Statement Presentation		69
Note 2 – Summary of Significant Accounting Policies		72
Note 3 – Recent Accounting Developments		80
Note 4 – Revenue Recognition		82
Note 5 – Financial Instruments		82
Note 6 – Cumulative Effect of Changes in Accounting Principles		83
Note 7 – Inventories		84
Note 8 – Property, Plant and Equipment		85
Note 9 – Investments in and Advances to Unconsolidated Affiliate		85
Note 10 – Intangible Assets		87
Note 11 – Debt Obligations		87
Note 12 – Partners’ Equity/Owners’ Net Investment and Distributions		90
Note 13 – Parent Interest in Subsidiaries		91
Note 14 – Business Segments		92
Note 15 – Related Party Transactions		96
Note 16 – Earnings Per Unit		102
Note 17 – Commitments and Contingencies		103
Note 18 – Significant Risks and Uncertainties		105
Note 19 – Supplemental Cash Flow Information		106
Note 20 – Quarterly Financial Information (Unaudited)		107
Note 21 – Subsequent Events		107

To the Board of Directors and Unitholders of
DEP Holdings, LLC, the general partner of Duncan Energy Partners L.P.
Houston, Texas

     We have audited the accompanying consolidated balance sheet of Duncan Energy Partners L.P. and subsidiaries (the “Company”) as of December 31, 2007 and the combined balance sheet of Duncan Energy Partners Predecessor (the “Predecessor”) as of December 31, 2006, and the related consolidated statements of operations and comprehensive income, cash flows and partners’ equity for the eleven months ended December 31, 2007 for the Company, and the related combined statements of operations and comprehensive income, cash flows and owners’ net investment for the month ended January 31, 2007 and for each of the two years in the period ended December 31, 2006 for the Predecessor. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

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

     In our opinion, such financial statements present fairly, in all material respects, the consolidated financial position of Duncan Energy Partners L.P. and subsidiaries at December 31, 2007, and the results of their consolidated operations and their cash flows for the eleven months in the period ended December 31, 2007 for the Company, and the combined financial position of Duncan Energy Partners Predecessor at December 31, 2006, and the combined results of its operations and its cash flows for the month ended January 31, 2007, and each of the two years in the period ended December 31, 2006 for the Predecessor, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2008

DUNCAN ENERGY PARTNERS L.P.

		December 31,
		2007				2006
ASSETS
Current assets
Cash and cash equivalents		$	2,199			$	—
Accounts receivable – trade, net of allowance for doubtful accounts of $47 at December 31, 2007 and $402 at December 31, 2006			77,912				71,776
Accounts receivable – related parties			3,007				—
Inventories			8,510				13,538
Prepaid and other current assets			2,772				792
Total current assets			94,400				86,106
Property, plant and equipment, net			877,510				707,649
Investments in and advances to unconsolidated affiliate			3,490				3,391
Intangible assets, net of accumulated amortization of $1,393 at December 31, 2007 and $1,161 at December 31, 2006			6,733				6,966
Other assets			273				—
Total assets		$	982,406			$	804,112
LIABILITIES AND PARTNERS’ EQUITY/OWNERS’ NET INVESTMENT
Current liabilities
Accounts payable – trade		$	17,367			$	702
Accounts payable – related parties			21,712				—
Accrued products payables			57,474				62,571
Accrued costs and expenses			1,204				5,093
Accrued interest			186				—
Other current liabilities			7,537				9,263
Total current liabilities			105,480				77,629
Long-term Debt (See Note 11)			200,000				—
Other long-term liabilities			3,937				686
Parent interest in subsidiaries			356,214				—
Commitments and Contingencies
Partners’ equity/Owners’ net investment:
Limited partners (20,301,571 common units outstanding at December 31, 2007)			319,769				—
General partner			599				—
Accumulated other comprehensive loss			(3,593	)			—
Owners’ net investment – Predecessor			—				725,797
Total partners’ equity/owners’ net investment			316,775				725,797
Total liabilities and partners’ equity/owners’ net investment		$	982,406			$	804,112

See Notes to Financial Statements

DUNCAN ENERGY PARTNERS L.P.

		Duncan Energy
		Partners					Duncan Energy Partners Predecessor
		For the Eleven					For the One				For the
		Months Ended					Month Ended				Year Ended
		December 31,					January 31,				December 31,
		2007					2007				2006				2005
Revenues
Third parties			$482,414					$42,657				$528,501				$534,568
Related parties			314,630					24,017				395,977				418,829
Total revenues (see Note 14)			797,044					66,674				924,478				953,397
Costs and expenses
Operating costs and expenses
Third parties			703,374					58,038				815,252				848,066
Related parties			41,652					3,149				51,808				60,978
Total operating costs and expenses			745,026					61,187				867,060				909,044
General and administrative costs
Third parties			1,619					22				203				546
Related parties			2,403					455				3,283				3,937
Total general and administrative costs			4,022					477				3,486				4,483
Total costs and expenses			749,048					61,664				870,546				913,527
Equity in income of unconsolidated affiliate			157					25				958				331
Operating income			48,153					5,035				54,890				40,201
Other income (expense)
Interest expense			(9,279	)				—				—				—
Interest income			638					—				—				—
Other, net			—					—				459				(532	)
Other expense			(8,641	)				—				459				(532	)
Income before provision for income taxes, parent interest in subsidiaries and cumulative effect of changes in accounting principles			39,512					5,035				55,349				39,669
Provision for income taxes			(307	)				—				(21	)			—
Income before parent interest in income of subsidiaries and the cumulative effect of changes in accounting principle			39,205					5,035				55,328				39,669
Parent interest in income of subsidiaries			(19,973	)				—				—				—
Income before the cumulative effect of changes in accounting principle			19,232					5,035				55,328				39,669
Cumulative effect of changes in accounting principles (see Note 6)			—					—				9				(582	)
Net income			19,232					5,035				55,337				39,087
Change in fair value of cash flow hedges			(3,593	)				—				—				—
Comprehensive income			$  15,639					$   5,035				$55,337				$39,087
Net income allocation: (see Note 12)
Limited partners’ interest in net income			$  18,847
General partner interest in net income			$       385
Earnings per unit : (see Note 16)
Basic and diluted income per unit			0.93