As filed with the Securities and Exchange Commission on December 15, 2006

Registration No. 333-138371

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

AMENDMENT NO. 1

TO

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

 

 

Duncan Energy Partners L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

 

 

 

1100 Louisiana Street, 10th Floor

Houston, Texas 77002

(713) 381-6500

(Address, Including Zip Code, and Telephone Number, Including

Area Code, of Registrant’s Principal Executive Offices)

 

 

 

 

Richard H. Bachmann

1100 Louisiana Street, 10th Floor

Houston, Texas 77002

(713) 381-6500

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

 

 

Copies to:

 

 

 

 

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

 

 

 

 

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  o

 

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

 

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

 

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

 

 

 

 

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

 

 

Subject to Completion, dated December 15, 2006

 

PROSPECTUS

 

 

13,000,000 Common Units

Representing Limited Partner Interests

 

 

Duncan Energy Partners L.P. is a limited partnership recently formed by Enterprise Products Partners L.P. This is the initial public offering of our common units. We currently estimate that the initial public offering price will be between $      and $      per common unit. Before this offering, there has been no public market for our common units. We have applied to list the common units on the New York Stock Exchange under the symbol “DEP.”

 

Investing in our common units involves risks.  Please read “Risk Factors” beginning on page 22.

 

These risks include the following:

 

 

 

 

 

 

We have granted the underwriters a 30-day option to purchase up to an additional 1,950,000 common units on the same terms and conditions as set forth above if the underwriters sell more than 13,000,000 common units in this offering.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

 

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about          , 2007.

 

Lehman Brothers

          , 2007

 

TABLE OF CONTENTS

 

 

 

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with

different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition and results of operations may have changed since that date.

 

Until          , 2007 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

SUMMARY

 

Duncan Energy Partners L.P.

	•	NGL & Petrochemical Storage Services.  Our NGL & Petrochemical Storage Services segment consists of 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 MMBbls, and certain related assets. These assets receive, store and deliver NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States.
	•	Natural Gas Pipelines & Services.  Our Natural Gas Pipelines & Services segment consists of the Acadian Gas system, which is an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. In the aggregate, the Acadian Gas system includes over 1,000 miles of high-pressure transmission lines and lateral and gathering lines with an aggregate throughput capacity of approximately one Bcf/d and a leased storage facility with approximately three Bcf of storage capacity.

	•	Petrochemical Pipeline Services.  Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline. The Lou-Tex Propylene pipeline system consists of a 263-mile pipeline used to transport chemical-grade propylene between

		Sorrento, Louisiana and Mont Belvieu, Texas. The Sabine Propylene pipeline system consists of 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.

	•	NGL Pipeline Services.  Our NGL Pipeline Services segment will consist of a 290-mile pipeline system used to transport NGLs from two Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas and related interconnections. We acquired a 223-mile segment of the system in August 2006, and we are in the process of acquiring and constructing other segments of the pipeline. The system is not in operation, but it is currently undergoing modifications, extensions and interconnections that should allow it to transport NGLs beginning in January 2007. Additional expansions are scheduled to be completed during 2007.

	•	optimize the benefits of our 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 which 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.

	•	our operations currently consist of mature assets and a new NGL pipeline which are expected to generate stable, predictable cash flows;
	•	our assets are strategically located in areas with high demand for our services and play a critical role in Enterprise Products Partners’ midstream energy value chain;
	•	Enterprise Products Partners and EPCO have established a reputation in the midstream natural gas and NGL industries as reliable and cost-effective operators;
	•	the senior management team and board of directors of our general partner have extensive industry experience and include some of the most senior officers of EPCO;
	•	we have a lower cost of capital than other publicly traded partnerships that have incentive distribution rights; and
	•	our affiliation with Enterprise Products Partners and its affiliates may provide us access to attractive acquisition opportunities from them and third parties.

	•	Enterprise Products OLP will contribute to us 66% of the equity interests in Mont Belvieu Caverns, Acadian Gas, Sabine Propylene, Lou-Tex Propylene and South Texas NGL;

	•	We will issue to Enterprise Products OLP 7,301,571 common units representing an approximate 35.2% limited partner interest in us (or an approximate 25.8% limited partner interest if the underwriters exercise in full their option to purchase additional common units), and we will issue a 2% general partner interest to our general partner, DEP Holdings, LLC;

	•	We will borrow approximately $200 million under a new credit agreement that we anticipate entering into prior to the closing of this offering, which will be used to fund a portion of our payment to Enterprise Products Partners in connection with the transactions described above;
	•	We will sell 13,000,000 common units to the public in this offering representing an approximate 62.8% limited partner interest in us (or an approximate 72.2% limited partner interest if the underwriters exercise in full their option to purchase additional common units), and will use the net proceeds from this offering as described under “Use of Proceeds;”
	•	We will become party to an existing administrative services agreement among EPCO and certain of their affiliates;
	•	We will enter into various new transportation, storage and operating agreements with Enterprise Products OLP and its affiliates; and

	•	We will enter into an omnibus agreement with Enterprise Products OLP, pursuant to which Enterprise Products OLP will agree to (i) indemnify us for certain environmental liabilities, tax liabilities and title and right-of-way defects occurring or existing before the closing and (ii) reimburse us for our 66% share of excess construction costs, if any, above our current estimated cost to complete planned expansions on the South Texas NGL pipeline. In addition, we will grant Enterprise Products OLP a right of first refusal on the equity interests in certain of our operating subsidiaries and on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business.

										% of
		General Partner								Total
		Units				Common Units				Ownership
Public common units			—				13,000,000				62.8	%
Enterprise Products Partners and its affiliates			—				7,301,571				35.2	%
General partner interest			414,318				—				2.0	%
Total			414,318				20,301,571				100.0	%

 

The Offering

Common units offered		13,000,000 common units.
Common units subject to the underwriters’ option to purchase additional common units		If the underwriters exercise their option to purchase additional units in full, we will issue 1,950,000 additional common units to the public and redeem 1,950,000 common units from Enterprise Products OLP, who may be deemed to be a selling unitholder in this offering. Please read “Selling Unitholder.”

Common units outstanding after this offering		20,301,571 common units.

Use of proceeds		We will use the net proceeds from this offering of approximately $243.4 million (based on an assumed offering price of $20.00 per unit), after deducting the underwriting discount and a $1.0 million structuring fee, but before estimated expenses associated with the offering and related formation transactions, to:

		• distribute approximately $221.6 million to Enterprise Products OLP as a portion of the cash consideration and reimbursement for capital expenditures relating to the assets contributed to us;

		• provide approximately $18.9 million to fund our share of estimated capital expenditures to complete planned expansions to the South Texas NGL pipeline subsequent to the closing of this offering; and

		• pay approximately $2.9 million of other estimated net expenses associated with this offering and related formation transactions described on page 3.

		In addition, we will borrow approximately $200 million under a new $300 million credit agreement that we will enter into prior to the closing of this offering, and we will distribute $198.9 million of these borrowings to Enterprise Products OLP in partial consideration for the assets contributed to us upon the closing of this offering.

		If the underwriters exercise their option to purchase additional common units, we will use all of the net proceeds from the sale of those common units to redeem an equal number of common units from Enterprise Products OLP. For the resulting beneficial ownership, read “Security Ownership of Certain Beneficial Owners and Management.”

Cash distributions		We will make initial quarterly distributions of $0.40 per common unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner.

		We refer to this cash as “available cash,” and we define its meaning in our partnership agreement as summarized in “How We Make Cash Distributions — Distributions of Available Cash — Definition of Available Cash.” The amount of available cash may be greater than or less than the aggregate amount associated with payment of the expected initial quarterly distribution on all common units. In general, we will pay 98% of any cash distributions we make each quarter to our unitholders and the remaining 2% to our general partner.

		Unlike many publicly traded limited partnerships, our general partner is not entitled to any incentive distributions and we do not have any subordinated units.

		We believe that, based on the assumptions and considerations described in “Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations,” we will have sufficient available cash to pay the full initial quarterly distribution on all our common units and our general partner interest for each quarter during the four quarters ending December 31, 2007. We estimate that our pro forma available cash for the year ended December 31, 2005 would have been sufficient to pay only 30% of the initial quarterly distributions on our common units and our general partner interest during that period. We estimate that our pro forma available cash for the four quarters ended September 30, 2006 would not have been sufficient to pay any distributions on our common units and our general partner interest.

		We will pay investors in this offering a prorated distribution for the first quarter during which we are a publicly traded partnership. This distribution will be paid for the period beginning on the first day our common units are publicly traded and ending on the last day of that fiscal quarter. Therefore, we will pay investors in this offering a distribution for the period from the closing date of this offering to and including March 31, 2007. We expect to pay this cash distribution on or about May 15, 2007.
Limited call right		If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.
Issuance of additional units		We can issue an unlimited number of units without the consent of our unitholders. Please read “Common Units Eligible For Future Sale” and “Description of Material Provisions of Our Partnership Agreement — Issuance of Additional Securities.”
Limited voting rights		Our general partner will manage all of our operations. Unlike the holders of common stock of a corporation, you will have only limited voting rights on matters affecting our business and you will have no right to elect our general partner or its officers or directors. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding common units, including common units owned by our general partner and its affiliates. Upon completion of this offering, affiliates of our

		general partner will own approximately 36.0% of our outstanding common units (or approximately 26.4% of our outstanding common units if the underwriters’ option to purchase additional common units is exercised in full). Please read “Description of Material Provisions of Our Partnership Agreement — Withdrawal or Removal of Our General Partner.”

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than  % of the cash distributed with respect to that period. For example, if you receive an annual distribution of $      per common unit, we estimate that your average allocated federal taxable income per year will be no more than $      per unit. Please read “Material Tax Consequences” in this prospectus for the basis of this estimate.
Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Exchange listing		We have applied to list our common units on the New York Stock Exchange under the symbol “DEP.”

 

Summary of Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties

	•	if a business opportunity to acquire certain equity securities (which we define to include general partner interests in publicly traded partnerships and similar interests and any associated incentive distribution rights, limited partner interests or similar interests owned by the owner of such general partner interest or its affiliates), is presented to the EPCO Group, us, and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, Enterprise GP Holdings will have the first right to pursue the acquisition. In the event that Enterprise GP Holdings abandons the acquisition, Enterprise Products Partners will have the second right to pursue such acquisition either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of us. In the event that Enterprise Products Partners affirmatively directs the acquisition to us, we may pursue such acquisition. In the event that Enterprise Products Partners abandons the acquisition for itself and for us, the EPCO Group may pursue the acquisition without any further obligation to any other party or offer such opportunity to other affiliates; and
	•	if any business opportunity not covered by the preceding bullet point is presented to the EPCO Group, us and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of us. In the event that Enterprise Products Partners affirmatively directs the business opportunity to us, we may pursue such business opportunity. In the event Enterprise Products Partners abandons the business opportunity for itself and for us, Enterprise GP Holdings will have the second right to pursue such business opportunity. In the event Enterprise GP Holdings abandons the business opportunity, the EPCO Group may pursue the business opportunity without any further obligation to any other party or offer such opportunity to other affiliates.

 

Summary of Certain Risk Factors

	•	We may not have sufficient cash from operations to enable us to pay our expected initial quarterly distribution on our common units.

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

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

	•	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.

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

	•	Federal, state or local regulatory measures could materially adversely affect our business, results of operations, cash flows and financial condition.
	•	Environmental costs and liabilities and changing environmental regulation could materially affect our results of operations, cash flows and financial condition.

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

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

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

	•	Affiliates of our general partner, including Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners, may compete with us, and business opportunities may be directed by contract to Enterprise Products Partners and Enterprise GP Holdings before us under the administrative services agreement.

	•	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.

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

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

	•	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.

	•	You will experience immediate and substantial dilution of $6.77 per common unit.

	•	We may issue additional units without your approval, which would dilute your ownership interests.
	•	Cost reimbursements to EPCO and its affiliates will reduce cash available for distribution to you.

	•	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 Internal Revenue Service, or the IRS, were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to you would be substantially reduced.
	•	If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any contest will reduce our cash distributions to you.
	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

Summary Historical and Pro Forma Financial and Operating Data

	•	The August 2006 purchase of a pipeline by Enterprise Products Partners for approximately $97.7 million in cash, the subsequent contribution of this pipeline to South Texas NGL, and estimated additional costs of $37.7 million required to modify this pipeline and to acquire and construct additional pipelines in order to place this system into operation in January 2007. The pro forma financial data does not reflect estimated additional capital expenditures of $28.6 million that will be made by South Texas NGL in 2007 to complete planned expansions to this system. We will retain cash in an amount equal to our 66% share (approximately $18.9 million) of these estimated capital expenditures from the net proceeds of this offering in order to fund our share of the planned expansion costs. The pro forma combined results of operations data does not reflect any results attributable to the historical activities of this pipeline.

	•	The contribution of a 66% interest in certain entities, which are wholly-owned subsidiaries of Enterprise Products Partners, and the retention by Enterprise Products Partners of a 34% interest in these entities.
	•	The revision of related party storage contracts between us and Enterprise Products Partners to (1) increase certain storage fees paid by Enterprise Products Partners and (2) reflect the allocation to Enterprise Products Partners of all storage measurement gains and losses relating to products under these agreements, and the execution of a limited liability company agreement for Mont Belvieu Caverns providing for the special allocation and other agreements relating to other measurement gains and losses to Enterprise Products Partners.

	•	The assignment to us of certain third-party agreements that effectively reduce tariff rates received by us for the transport of propylene volumes.

	•	our borrowing of $200 million under a new revolving credit facility;

	•	our issuance and sale of 13,000,000 common units to the public in this offering;
	•	our payment of estimated underwriting discounts and commissions, a structuring fee and other offering expenses; and
	•	our use of net proceeds from the borrowing and this offering as consideration for the contributed ownership interests in Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL from Enterprise Products Partners.

														Duncan Energy Partners L.P.
														For the Year Ended
		Duncan Energy Partners Predecessor												December 31, 2005
		For the Year Ended December 31,												Pro				Pro Forma
		2003				2004				2005				Forma				As Adjusted
Combined Results of Operations Data:(1)
Revenues		$	668,234			$	748,931			$	953,397			$	946,568			$	946,568
Costs and expenses:
Operating costs and expenses			609,774				685,544				909,044				905,989				905,989
General and administrative expenses			6,138				5,442				4,483				6,983				6,983
Total costs and expenses			615,912				690,986				913,527				912,972				912,972
Equity in income of unconsolidated affiliates			131				231				331				331				331
Operating income			52,453				58,176				40,201				33,927				33,927
Interest expense											(532	)			(532	)			(13,807	)
Other income (expense), net			1				(52	)
Total other income (expense)			1				(52	)			(532	)			(532	)			(13,807	)
Income before parent interest			52,454				58,124				39,669				33,395				20,120
Parent’s share of income																			(14,274	)
Income from continuing operations			52,454				58,124				39,669			$	33,395			$	5,846
Cumulative effect of change in accounting principle											(582	)
Net income		$	52,454			$	58,124			$	39,087
Earnings per unit — public, basic and diluted																		$	0.45
Combined Balance Sheet Data (at period end):(1)
Total assets		$	581,816			$	590,487			$	642,840
Owners’ net investment			524,127				509,719				527,767
Other Combined Financial Data:(1)
Net cash flows provided by operating activities		$	64,732			$	79,463			$	40,568
Cash flows used in investing activities			340				6,931				19,503
Cash flows used in (provided by) financing activities (2)			64,392				72,532				21,065
Gross operating margin			76,473				81,985				64,142			$	60,368			$	60,368
EBITDA			70,336				76,498				59,072				53,380				39,106
Operating Data:(1)
Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (Bbtus/d)			600				645				640				640				640
Petrochemical Pipeline Services, net:
Petrochemical transportation volumes (MBbls/d)			40				39				33				33				33

		Duncan Energy								Duncan Energy Partners L.P.
		Partners Predecessor								For the Nine Months
		For the Nine Months								Ended September 30, 2006
		Ended September 30,								Pro				Pro Forma
		2005				2006				Forma				As Adjusted
Combined Results of Operations Data:(1)
Revenues		$	649,404			$	740,102			$	733,434			$	733,434
Costs and expenses:
Operating costs and expenses			614,328				697,979				696,511				696,511
General and administrative expenses			3,799				2,469				4,344				4,344
Total costs and expenses			618,127				700,448				700,855				700,855
Equity in income of unconsolidated affiliates			280				624				624				624
Operating income			31,557				40,278				33,203				33,203
Interest expense															(9,930	)
Other income							6				6				6
Total other income (expense)							6				6				(9,924	)
Income before provision for income taxes and parent interest			31,557				40,284				33,209				23,279
Provision for income taxes							(21	)			(21	)			(21	)
Income before parent interest			31,557				40,263				33,188				23,258
Parent’s share of net income															(15,733	)
Income from continuing operations			31,557				40,263			$	33,188			$	7,525
Cumulative effect of change in accounting principle							9
Net income		$	31,557			$	40,272
Earnings per unit — public, basic and diluted														$	0.58
Combined Balance Sheet Data (at period end):(1)
Total assets		$	617,402			$	747,155			$	778,396			$	798,372
Total debt															200,000
Parent’s interest in the Partnership															274,642
Owners’ net investment			520,727				662,131				695,186
Partners’ equity — public															240,520
Other Combined Financial Data:(1)
Net cash flows provided by operating activities		$	37,226			$	62,301
Cash flows used in investing activities			16,669				58,226
Cash flows used in financing activities(2)			20,557				4,075
Gross operating margin			49,611				58,198			$	52,998			$	52,998
EBITDA			45,810				55,761				48,677				32,944
Operating Data:(1)
Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (Bbtus/d)			657				773				773				773
Petrochemical Pipeline Services, net:
Petrochemical transportation volumes (MBbls/d)			34				36				36				36

	•	Enterprise Products Partners owned Mont Belvieu Caverns and Lou-Tex Propylene for all periods presented.
	•	Enterprise Products Partners acquired Acadian Gas in April 2001; therefore, the selected data includes Acadian Gas from the date of its acquisition. No financial data was available from the seller for periods prior to April 2001.
	•	Enterprise Products Partners constructed the pipeline owned by Sabine Propylene and placed it in service in November 2001; therefore, the selected data includes Sabine Propylene from November 2001 to present.

	•	In August 2006, Enterprise Products Partners purchased a 223-mile pipeline extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for this asset was approximately $97.7 million in cash. This pipeline system will be owned by South Texas NGL (along with others being constructed and to be acquired) and will be used to transport NGLs from two Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas. The total estimated cost to acquire and construct the additional pipelines is $66.3 million. Our pro forma balance sheet data reflects assumed capital expenditures of $37.7 million, including approximately $8 million to purchase a 10-mile pipeline from TEPPCO Partners, to make this pipeline system operational prior to the closing of this offering. We expect that it will cost an additional $28.6 million to complete planned expansions of the South Texas NGL pipeline after the closing of this offering, of which our 66% share will be approximately $18.9 million. This expenditure is not reflected in the pro forma financial data because we expect to use cash on hand from the proceeds of this offering to fund this cost.

														Duncan Energy Partners L.P.
														For the Year Ended
														December 31, 2005
		Duncan Energy Partners Predecessor																Pro Forma
		For the Year Ended December 31,												Pro				As
		2003				2004				2005				Forma				Adjusted
Reconciliation of GAAP “operating income” to non-GAAP “gross operating margin”
Operating income		$	52,453			$	58,176			$	40,201			$	33,927			$	33,927
Adjustments to reconcile operating income to gross operating margin:
Depreciation, amortization and accretion in operating costs and expenses			17,882				18,374				19,453				19,453				19,453
Loss (gain) on sale of assets in operating costs and expenses							(7	)			5				5				5
General and administrative costs			6,138				5,442				4,483				6,983				6,983
Total gross operating margin		$	76,473			$	81,985			$	64,142			$	60,368			$	60,368
Reconciliation of non-GAAP “EBITDA” to GAAP “net income” (or GAAP “income from continuing operations” with respect to pro forma data) and GAAP “net cash provided by operating activities”
Net income (income from continuing operations with respect to pro forma data)		$	52,454			$	58,124			$	39,087			$	33,395			$	5,846
Additions to income to derive EBITDA:
Interest expense											532				532				13,807
Depreciation, accretion and amortization			17,882				18,374				19,453				19,453				19,453
EBITDA		$	70,336			$	76,498			$	59,072			$	53,380			$	39,106
Adjustments to EBITDA to derive net cash provided by operating activities (add or subtract as indicated by sign of number):
Cumulative effect of change in accounting principle											582
Interest expense											(532	)
Equity in income of unconsolidated affiliates			(131	)			(231	)			(331	)
Loss (gain) on sale of assets							(7	)			5
Changes in fair market value of financial instruments			2				5				52
Net effect of changes in operating accounts			(5,475	)			3,198				(18,280	)
Net cash provided by operating activities		$	64,732			$	79,463			$	40,568

										Duncan Energy
										Partners L.P.
										For the Nine Months
		Duncan Energy								Ended September 30, 2006
		Partners Predecessor												Pro
		For the Nine Months												Forma
		Ended September 30,								Pro				As
		2005				2006				Forma				Adjusted
Reconciliation of GAAP “operating income” to non-GAAP “gross operating margin”
Operating income		$	31,557			$	40,278			$	33,203			$	33,203
Adjustments to reconcile operating income to gross operating margin:
Depreciation, amortization and accretion in operating costs and expenses			14,253				15,468				15,468				15,468
Loss (gain) on sale of assets in operating costs and expenses			2				(17	)			(17	)			(17	)
General and administrative costs			3,799				2,469				4,344				4,344
Total gross operating margin		$	49,611			$	58,198			$	52,998			$	52,998
Reconciliation of non-GAAP “EBITDA” to GAAP “net income” (or GAAP “income from continuing operations” with respect to pro forma data) and GAAP “net cash provided by operating activities”
Net income (income from continuing operations with respect to pro forma data)		$	31,557			$	40,272			$	33,188			$	7,525
Additions to income to derive EBITDA:
Interest expense															9,930
Provision for income taxes							21				21				21
Depreciation, accretion and amortization			14,253				15,468				15,468				15,468
EBITDA		$	45,810			$	55,761			$	48,677			$	32,944
Adjustments to EBITDA to derive net cash provided by operating activities (add or subtract as indicated by sign of number):
Provision for income taxes							(21	)
Cumulative effect of change in accounting principle							(9	)
Equity in income of unconsolidated affiliates			(280	)			(624	)
Deferred income tax expense							21
Loss (gain) on sale of assets			2				(17	)
Changes in fair market value of financial instruments			(355	)			65
Net effect of changes in operating accounts			(7,951	)			7,125
Net cash provided by operating activities		$	37,226			$	62,301

 

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

 

If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

 

We may not have sufficient available cash to enable us to pay our expected initial quarterly distribution on our common units after establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner.

 

We may not have sufficient available cash each quarter to pay our expected initial quarterly distribution. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:

 

 

 

Please read “Cash Distribution Policy and Restrictions on Distributions” for a discussion of how we determine our available cash.

 

 

The amount of available cash we will need to pay our expected initial quarterly distribution for four quarters on the common units and the 2% general partner interest to be outstanding immediately after this offering is approximately $33.1 million. Pro forma combined available cash to make distributions generated during fiscal 2005 and the four quarters ended September 30, 2006 would have been approximately $9.9 million and a deficit of $14.1 million, respectively. These amounts would have been sufficient to allow us to pay only 30% of the initial quarterly distributions on the common units and the 2% general partner interest during 2005. These amounts would not have been sufficient to allow us to pay any distributions on our common units and the general partner interest during the four quarters ended September 30, 2006. For a calculation of our ability to make distributions to unitholders based on our pro forma results in 2005 and for the twelve months ended September 30, 2006, as well as estimated cash available to pay distributions for the four quarters ending December 31, 2007, please read “Cash Distribution Policy and Restrictions on Distributions.”

 

 

Our estimate of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. Furthermore, our estimate of cash available for distribution for the four quarters ending December 31, 2007 is equal to the amount of available cash we need to pay the expected initial quarterly distribution on all common units for such quarters. If we do not achieve the estimated results, we may not be able to pay the full expected initial quarterly distribution or any amount on our common units, in which event the market price of our common units may decline materially.

 

 

The amount of cash we have available for distribution depends primarily on our cash flow, including cash flow from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

 

 

We operate predominantly in the midstream energy sector which includes transporting and storing natural gas, NGLs and propylene. As such, our results of operations, cash flows and financial condition may be materially adversely affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. Changes in prices and changes in the relative price levels may impact demand for hydrocarbon products, which in turn may impact production and volumes

transported by us and related transportation and storage handling fees. We may also incur price risk to the extent counterparties do not perform in connection with our marketing of natural gas, NGLs and propylene.

 

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

 

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

 

 

 

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

 

 

 

Over the past two years that have been reported, gas production from state waters of the Gulf Coast region, which supplies much of our throughput, has declined an average of approximately 2.9% from 133 Bcf

for 2003 to 129 Bcf for 2004, according to the Energy Information Administration, or EIA. We cannot give any assurance regarding the gas production industry’s ability to find new sources of domestic supply. Production from existing wells and gas supply basins connected to our pipelines will naturally decline over time, which means that our cash flows associated with the gathering or transportation of gas from these wells and basins will also decline over time. The amount of natural gas reserves underlying these wells may also be less than we anticipate, and the rate at which production from these reserves declines may be greater than we anticipate. Accordingly, to maintain or increase throughput levels on our pipelines, we must continually obtain access to new supplies of natural gas. The primary factors affecting our ability to obtain new sources of natural gas to our pipelines include:

 

 

The level of drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is the price of oil and natural gas. These commodity prices reached record levels during 2006, but current prices have declined in recent months. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our pipelines, which would lead to reduced throughput levels on our pipelines. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits, the availability and cost of drilling rigs and other drilling equipment, and regulatory changes. Because of these factors, even if new natural gas reserves were discovered in areas served by our pipelines, producers may choose not to develop those reserves or may connect them to different pipelines.

 

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

 

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

 

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

 

In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves connected to our pipeline systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems (or to processing facilities such as those serving Enterprise Products Partners in South Texas) or the anticipated lives of such reserves. If the total reserves or estimated lives of the reserves connected to our pipeline systems, particularly in South Texas, is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our South Texas NGL and other pipeline

systems in the future could be less than we anticipate. A decline in the volumes of natural gas gathered on our pipeline systems could have an adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.

 

 

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

 

Any adverse changes in the business of Enterprise Products Partners, due to market conditions, sales of assets or otherwise, or the failure of Enterprise Products Partners to renew any of its material agreements with us, could reduce our revenue, earnings or cash available for distribution. Please read “Certain Relationships and Related Party Transactions” for a summary of certain of these agreements.

 

 

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

 

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

 

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

 

 

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.

 

 

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

 

 

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisition, investments or capital expenditures, selling assets,

restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

 

 

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 new credit agreement will restrict or limit our ability to:

 

 

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

 

 

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

 

 

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, please read “Management’s Discussion and

Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Revolving Credit Facility.”

 

 

We have significant exposure to increases in interest rates. After giving effect to this offering and the borrowing of approximately $200 million under our new credit agreement, pro forma as of September 30, 2006, we would have approximately $200 million of consolidated debt, of which we expect all will be at variable interest rates. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

 

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

 

 

We utilize derivative financial instruments related to the future price of natural gas and the future price of NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices. While our hedging activities are designed to reduce commodity price risk, we remain exposed to fluctuations in commodity prices to some extent. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual natural gas prices or NGLs prices that we realize in our operations. Furthermore, our hedges relate to only a portion of the volume of our expected sales and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Our actual future sales may be significantly higher or lower than estimated at the time we entered into derivative transactions for such period. If the actual amount is higher than estimated, we will have greater commodity price exposure than intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from the sale or purchase of the underlying physical commodity, resulting in a substantial diminution of liquidity.

 

As a result of these factors, our hedging activities may not be as effective as intended in reducing the volatility of our cash flows, which could adversely affect our ability to make distributions to unitholders. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging procedures may not be properly followed. We cannot assure you that the steps we take to monitor our derivative financial instruments will detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

 

 

Our South Texas NGL pipeline system will not be placed into operation or generate cash flow until we complete construction of a pipeline connecting it to Mont Belvieu, Texas. While we anticipate that construction of this pipeline will be complete and operations will commence in early January 2007, we cannot be certain that this construction project will be finished and the pipeline placed in service before the completion of this offering. In addition, one of the connections between our South Texas pipeline and the Mont Belvieu facility will be a pipeline we will lease from TEPPCO Partners. The initial term of this lease will expire on July 31, 2007, and if we are unable to construct our planned replacement pipeline or extend the lease, the operations of our South Texas NGL pipeline will be interrupted. We cannot assure you that any

construction will not be delayed due to government permits, weather conditions or other factors beyond our control.

 

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

 

 

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

 

 

We will be limited in our ability to make acquisitions by our business opportunity agreements with Enterprise Products Partners and Enterprise GP Holdings. These agreements will 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.

 

 

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

 

 

 

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

 

 

The Surface Transportation Board, or STB, regulates transportation on interstate propylene pipelines. The current version of the Interstate Commerce Act, or 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 Natural Gas Policy Act of 1978, or NGPA. Pursuant to the NGPA, we are required to offer those services on an open and nondiscriminatory basis at a fair and equitable rate. Such FERC-regulated NGPA Section 311 rates also may be subject to challenge and successful challenges may adversely affect our revenues.

 

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

 

For a general overview of federal, state and local regulation applicable to our assets, please read “Business — Regulation of Operations.”

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 have been appealed to the United States Court of Appeals for the District of Columbia Circuit. As a result, the ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. Depending upon how the policy statement on income tax allowances is applied in practice to pipelines organized as pass-through entities, and whether it is ultimately upheld or modified on judicial review, these decisions might adversely affect us.

 

 

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. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the discharge of waste from our facilities and (3) the Comprehensive Environmental Response Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the clean up of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to administrative, civil and criminal penalties, including substantial fines, the imposition of remedial requirements, and the issuance of orders enjoining future operations. 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.