EX-99 2 exhibit99-1.htm GENERAL PARTNER'S BALANCE SHEET

EXHIBIT 99.1

Enterprise Products GP, LLC

Unaudited Consolidated Balance Sheet as of June 30, 2004

ENTERPRISE PRODUCTS GP, LLC

Unaudited Consolidated Balance Sheet

Notes to Unaudited Consolidated Balance Sheet

ENTERPRISE PRODUCTS GP, LLC
UNAUDITED CONSOLIDATED BALANCE SHEET
AT JUNE 30, 2004
(Dollars in thousands)

ASSETS	June 30, 2004
Current Assets
Cash and cash equivalents (includes restricted cash of $23,137)	$	62,628
Accounts and notes receivable - trade, net of allowance for doubtful
accounts of $21,129		514,799
Accounts receivable - related parties		20,856
Inventories		203,796
Prepaid and other current assets		37,629

Total current assets		839,708
Property, Plant and Equipment, Net		3,020,819
Investments in and Advances to Unconsolidated Affiliates		718,705
Intangible assets, net of accumulated amortization of $48,016		261,248
Goodwill		82,427
Deferred Tax Asset		8,096
Long-term Receivables		5,112
Other Assets		16,947

Total	$	4,953,062


LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Current maturities of debt	$	364,974
Accounts payable - trade		22,025
Accounts payable - related parties		37,284
Accrued gas payables		757,656
Accrued expenses		17,059
Accrued interest		45,083
Other current liabilities		53,733

Total current liabilities		1,297,814
Long-Term Debt		1,402,370
Other Long-Term Liabilities		22,550
Minority Interest		2,081,334
Commitments and Contingencies
Members’ Equity		148,994

Total	$	4,953,062

See notes to unaudited consolidated balance sheet.

ENTERPRISE PRODUCTS GP, LLC
NOTES TO UNAUDITED CONSOLIDATED BALANCE SHEET

1. ORGANIZATION AND CONSOLIDATION

ENTERPRISE PRODUCTS GP, LLC (“EPGP”) is a privately-held Delaware limited liability company formed in May 1998 to become the general partner of Enterprise Products Partners L.P. (“EPD”) and its wholly owned operating subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”). Our primary business purpose is to manage the affairs and operations of EPD and its subsidiaries. EPD is a publicly traded Delaware limited partnership listed on the New York Stock Exchange (“NYSE”) under symbol “EPD.” EPD conducts substantially all of its business through the Operating Partnership. EPD and the Operating Partnership were formed to acquire, own and operate the natural gas liquids (“NGL”) business of EPCO, Inc. (“EPCO”, formerly Enterprise Products Company).

Unless the context requires otherwise, references to “we”, “us”, “our” or the “Company” within these notes shall mean EPGP and its consolidated subsidiaries, which include EPD and its subsidiaries. References to “Shell” shall mean Shell Oil Company, its subsidiaries and affiliates. References to “El Paso” shall mean El Paso Corporation and its affiliates.

At June 30, 2004, Duncan Family Interests, Inc. (“DFI”, formerly EPC Partners II, Inc.) owned 95%, and Dan Duncan, LLC owned 5% of the membership interests of EPGP. DFI and Dan Duncan, LLC are hereafter collectively referred to as the “Members.” EPCO is the ultimate parent of DFI and an affiliate of Dan Duncan, LLC.

As a result of DFI acquiring Shell’s 30% member interest in EPGP on September 12, 2003, the financial statements of EPD were consolidated with those of EPGP beginning in September 2003. This accounting consolidation is required because Shell’s minority interest rights in EPGP (which gave them significant participating rights) were terminated as a result of the purchase. This fact, along with DFI’s indirect control of EPD through its majority common unit holdings, gives EPGP the ability to exercise control over EPD. All intercompany accounts and transactions have been eliminated in consolidation.

EPD and its subsidiaries conduct substantially all of our business. We have no independent operations and no material assets outside those of EPD. The number of reconciling items between our consolidated balance sheet and that of EPD are few. The most significant is that relating to minority interest in our net assets by the limited partners of EPD and the elimination of our investment in EPD with our underlying partner’s capital account in EPD. See Note 9 for additional details of minority interest in our consolidated subsidiaries.

In the opinion of the Company, the accompanying unaudited consolidated balance sheet includes all adjustments consisting of normal recurring accruals necessary for a fair presentation. Although we believe the disclosures are adequate to make the information presented in the unaudited balance sheet not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. EPGP’s unaudited June 30, 2004 balance sheet should be read in conjunction with its audited December 31, 2003 balance sheet filed on EPD’s Form 8-K (Commission File No. 1-14323) on March 22, 2004. In addition, this financial information should be read in conjunction with EPD’s Form 10-K for the year ended December 31, 2003 and its Form 10-Q for the three and six months ended June 30, 2004. Certain abbreviated entity names and other capitalized and industry terms used within these footnotes are defined in the glossary of EPD’s Form 10-Q for the three and six months ended June 30, 2004.

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

The following tables show the consolidation of EPD’s consolidated balance sheet at June 30, 2004 with that of our own (dollars in thousands):

	Consolidated EPD and subsidiaries		EPGP			Adjustments and Eliminations			Consolidated EPGP and subsidiaries
ASSETS
Current Assets
Cash and cash equivalents
(includes restricted cash of $23,137)	$	62,562	$	66					$	62,628
Accounts and notes receivable - trade, net of
allowance for doubtful accounts of $21,129		514,799								514,799
Accounts receivable - related parties		21,467		(955	)	$	344			20,856
Inventories		203,796								203,796
Prepaid and other current assets		37,629								37,629

Total current assets		840,253		(889	)		344			839,708
Property, Plant and Equipment, Net		3,020,819								3,020,819
Investments in and Advances
to Unconsolidated Affiliates		718,705		40,926			(40,926	)		718,705
Intangible assets, net of accumulated
amortization of $48,016		261,248								261,248
Goodwill		82,427								82,427
Deferred Tax Asset		8,096								8,096
Long-term Receivables		5,112								5,112
Other Assets		16,947								16,947

Total	$	4,953,607	$	40,037		$	(40,582	)	$	4,953,062

	Consolidated EPD and subsidiaries			EPGP		Adjustments and Eliminations			Consolidated EPGP and subsidiaries
LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Current maturities of debt	$	364,974							$	364,974
Accounts payable - trade		22,025								22,025
Accounts payable - affiliates		36,940				$	344			37,284
Accrued gas payables		757,656								757,656
Accrued expenses		17,059								17,059
Accrued interest		45,083								45,083
Other current liabilities ⁽¹⁾		53,563		$	170					53,733

Total current liabilities		1,297,300			170		344			1,297,814
Long-Term Debt		1,402,370								1,402,370
Other Long-Term Liabilities ⁽¹⁾		22,362			188					22,550
Commitments and Contingencies
Minority Interest		88,823					1,992,511			2,081,334

Members’ Equity
Partnership Equity
Limited Partners		2,005,368					(2,005,368	)
General Partner		40,926					(40,926	)
Treasury units		(11,185	)				11,185
Accumulated Other Comprehensive Income		109,315								109,315
Deferred compensation		(1,672	)				1,672

		2,142,752					(2,033,437	)		109,315
Members’ Equity					39,679					39,679

Total Members’ Equity										148,994

Total	$	4,953,607		$	40,037	$	(40,582	)	$	4,953,062


(1)	A change in accounting principle occurred on January 1, 2004 to change the method our majority owned BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method. These major maintenance costs, which typically result in facility shutdowns for 30 to 45 days, are principally comprised of amounts paid to third parties for materials, contract services, and other related items. We have historically used the expense-as-incurred method for planned major maintenance activities. The change in accounting for our majority owned BEF subsidiary conforms to the Company's accounting for all planned major maintenance costs and changes the method to better reflect expenses in the period incurred. As such, we believe the change is to a method that is preferable in the circumstances.

2. RECENTLY ISSUED ACCOUNTING STANDARDS

FIN 46, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51.” This interpretation of ARB No. 51 addresses requirements for accounting consolidation of a variable interest entity (“VIE”) with its primary beneficiary. In general, if an equity owner of a VIE meets certain criteria defined within FIN 46, the assets, liabilities and results of the activities of the VIE should be included in the consolidated financial statements of the owner. Our adoption of FIN 46 (as amended by FIN 46R) in 2003 has had no material effect on our consolidated financial statements.

Due to the complexity of FIN 46 (as amended by FIN 46R and interpreted), the FASB is continuing to provide guidance regarding implementation issues. Since this guidance is still continuing, our conclusions regarding the application of this guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of FIN 46.

EITF 03-16, “Accounting for Investments in Limited Liability Companies.” This accounting guidance requires that investments in limited liability companies (or “LLCs”) that have separate ownership accounts for each investor be accounted for similar to a limited partnership investment under SOP No. 78-9, “Accounting for Investments in Real Estate Ventures.” Under this new guidance (applicable for the period beginning July 1, 2004), investors are required to apply the equity method of accounting to their investments at a much lower ownership threshold (typically any ownership interest greater than 3-5%) than the 20% threshold applied under APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

Currently, we account for our 13.1% investment in Venice Energy Services Company, LLC (“VESCO”) using the cost method. As a result, we have recognized dividend income from VESCO to the extent that we have received cash distributions from them. In accordance with the new accounting guidance in EITF 03-16, we will record a retroactive cumulative effect adjustment equal to the difference between (i) equity earnings from VESCO that would have been recorded using the equity method in prior periods and (ii) the dividend income from VESCO that was recorded using the cost method. We are currently studying the effect that EITF 03-16 will have on our investment in VESCO; however, based on information available, we believe that the implementation of this new accounting guidance will result in an approximate $4 million gain that will be recorded as the cumulative effect of a change in accounting principle.

3. BUSINESS COMBINATIONS

During the first six months of 2004, we acquired an additional 16.7% membership interest in Tri-States and a 10% equity interest in Seminole. Due to the immaterial nature of each acquisition, individually and in the aggregate, our discussion of each of these transactions is limited to the following:

Acquisition of 16.7% interest in Tri-States. In April 2004, we acquired an additional 16.7% interest in Tri-States, which owns a mixed NGL pipeline located along the Mississippi, Alabama and Louisiana Gulf Coast. This system, in conjunction with the Wilprise and Belle Rose NGL pipelines, supply mixed NGLs to the BRF, Norco and Promix NGL fractionators located in south Louisiana. Due to this acquisition, Tri-States became a majority-owned consolidated subsidiary of ours on April 1, 2004. Previously, Tri-States was accounted for as an equity-method unconsolidated affiliate.

Acquisition of 10% interest in Seminole. In May 2004, we acquired an additional 10% equity interest in Seminole, which owns a regulated 1,281-mile pipeline that transports mixed NGLs and NGL products from the Hobbs hub on the Texas-New Mexico border and the Permian Basin area to southeast Texas. Our total ownership interest in Seminole is now 88.4%. The Seminole pipeline is interconnected with our Mid-America Pipeline System at the Hobbs hub. The primary source of throughput for Seminole is volume originating from the Mid-America system.

For the six months ended June 30, 2004, the following table shows (i) our allocation of the purchase price for acquisitions and (ii) the effects of consolidating entities that were formerly accounted for under the equity-method:

	16.7% interest in Tri-States			10% interest in Seminole		Total
Cash and cash equivalents	$	515				$	515
Accounts receivable		1,801					1,801
Inventories		1,943					1,943
Prepaid and other current assets		3,215					3,215
Property, plant and equipment, net		80,270		$	3,603		83,873
Investments in and advances to
unconsolidated affiliates		(42,597	)				(42,597	)
Accounts payable		(549	)				(549	)
Other current liabilities		(1,780	)				(1,780	)
Minority interest		(25,818	)		24,997		(821	)

Total net assets recorded		17,000			28,600		45,600
Investee cash balances
recorded upon consolidation		(515	)				(515	)

Business combinations, net of
cash received	$	16,485		$	28,600	$	45,085

Proposed merger with GulfTerra

On December 15, 2003, we and certain of our affiliates, El Paso, and GulfTerra and certain of its affiliates entered into a series of agreements under which one of our wholly-owned subsidiaries and GulfTerra would merge, with GulfTerra surviving the merger and becoming a wholly-owned subsidiary of ours.

On July 29, 2004, we held a special meeting at which EPD’s common unitholders approved the issuance of EPD common units pursuant to the merger agreement. On the same day, GulfTerra held a special meeting of its common and Series C unitholders, at which time the merger agreement was approved and adopted. The completion of the merger remains subject to regulatory approvals, including under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and the fulfillment or waiver of the other merger agreement closing conditions. While we cannot predict if and when all of the conditions of the proposed merger will be satisfied, we expect to complete the transaction in the third quarter of 2004.

In general, the proposed merger with GulfTerra involves the following three steps:

•

Step One. On December 15, 2003, we purchased a 50% membership interest in GulfTerra’s general partner (“GulfTerra GP”) for $425 million. GulfTerra’s general partner owns a 1% general partner interest in GulfTerra. This investment is accounted for using the equity method and is already recorded in our historical balance sheet at December 31, 2003. See Note 6 regarding preliminary estimates of the purchase price allocation for GulfTerra GP. This transaction is referred to as Step One of the proposed merger and will remain in effect even if the remainder of the proposed merger and post-merger transactions, which are referred to as Step Two and Step Three, do not occur.

•

Step Two. If all necessary regulatory approvals are received and the other merger agreement conditions are either fulfilled or waived and the following steps are consummated, we will own 100% of the limited and general partner interests in GulfTerra. At that time, the proposed merger will be accounted for using the purchase method, and GulfTerra will be a consolidated subsidiary of Enterprise. Step Two of the proposed merger includes the following transactions:

•

El Paso’s exchange of its remaining 50% membership interest in GulfTerra GP for a cash payment by us of $370 million (which will not be funded or reimbursed by EPD) and a 9.9% membership in us, and the subsequent capital contribution by us of such 50% membership interest in GulfTerra GP to EPD (without our receipt of additional General Partner interest, common units or other consideration).

•

Our purchase of 10,937,500 GulfTerra Series C units and 2,876,620 GulfTerra common units owned by El Paso for $500 million.

•

The exchange of each remaining GulfTerra common unit for 1.81 EPD common units, resulting in the issuance of approximately 105.1 million of our common units to GulfTerra unitholders.

•

Step Three. Immediately after Step Two is completed, we expect to acquire certain South Texas midstream energy assets from El Paso for $150 million plus the value of then existing inventories related to such assets.

We anticipate that a portion of the purchase price at the closing of Steps Two and Three of the proposed merger will be financed with the net proceeds from the sale of 17,250,000 EPD common units completed in August 2004. We expect to finance the remaining portion of this purchase price primarily through one or more issuances of debt securities, a temporary acquisition term facility, borrowings under our credit facility, or through any combination of the foregoing. The size, terms and timing of any future debt offerings are subject to market conditions that are beyond our control.

Our preliminary estimate of the total consideration for Steps One, Two and Three we would pay or issue is approximately $4.1 billion. For a period of three years following the closing of the proposed merger, at our request, El Paso will provide certain support services to GulfTerra similar to those provided by El Paso prior to the closing of the merger. GulfTerra will reimburse El Paso for 110% of its direct costs for such services (excluding any overhead costs). In addition, El Paso will make transition support payments to us in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. These transition support payments are included in our preliminary estimate of total consideration.

The completion of the merger is subject to customary regulatory approvals, including under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. We are in the process of negotiating a consent decree with the FTC for the divestiture of certain of our assets to resolve their competitive concerns. We do not believe these divestitures would be significant to the combined company’s business operations.

To review a copy of the merger agreement and related transaction documents, please read EPD’s Current Reports on Form 8-K filed with the SEC on December 15, 2003 and April 21, 2004.

4. INVENTORIES

Our inventories were as follows at June 30, 2004:

Working inventory	$	184,319
Forward-sales inventory		19,477

Inventory	$	203,796

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale or used in the provision of services. The forward sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of forward sales contracts. Both inventories are valued at the lower of average cost or market.

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment and accumulated depreciation were as follows at June 30, 2004:


Plants and pipelines (1)	5-35 (4)	$	3,370,873
Underground and other storage facilities (2)	5-35 (5)		289,539
Transportation equipment (3)	3-10		6,816
Land			23,410
Construction in progress			41,029

Total			3,731,667
Less accumulated depreciation			710,848

Property, plant and equipment, net		$	3,020,819


(1)	Plants and pipelines include processing plants; NGL, petrochemical and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets.
(2)	Underground and other storage facilities includes underground product storage caverns; storage tanks; water wells; and related assets.
(3)	Transportation equipment includes vehicles and similar assets used in our operations.
(4)	In general, the estimated useful lives of major components of this category are: processing plants, 20-35 years; pipelines, 3-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-35 years; and laboratory and shop equipment, 5-35 years.
(5)	In general, the estimated useful lives of major components of this category are: underground storage wells, 30-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

We own interests in a number of related businesses that are accounted for using the equity or cost methods. The investments in and advances to these unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of business segments, see Note 12. The following table shows our investments in and advances to unconsolidated affiliates:

			June 30, 2004
Accounted for using the equity method:
Pipeline:
GulfTerra GP	50	.0%	$	424,962
Neptune	25	.7%		72,641
Starfish	50	.0%		39,921
Dixie	19	.9%		35,497
Nemo	33	.9%		11,880
Belle Rose	41	.7%		10,322
Evangeline	49	.5%		2,807
Tri-States (1)	50	.0%
Fractionation:
Promix	33	.3%		39,117
BRF	32	.3%		27,126
BRPC	30	.0%		16,207
La Porte	50	.0%		5,225
Accounted for using the cost method:
Processing:
VESCO	13	.1%		33,000

Total			$	718,705


(1)	We acquired an additional 16.7% ownership interest in Tri-States in April 2004. As a result of this acquisition, Tri-States became a consolidated subsidiary.

Our initial investment in Promix, La Porte, Dixie, Tri-States, Neptune, Nemo and GulfTerra GP exceeded our share of the historical cost of the underlying net assets of such entities (“excess cost”). The excess cost amounts are reflected in our investments in and advances to unconsolidated affiliates for these entities. That portion of excess cost attributable to tangible or amortizable intangible assets of each entity is amortized over the estimated useful life of the underlying asset(s) as a reduction in equity earnings from the investee. That portion of excess cost attributable to goodwill or non-amortizable intangible assets is not amortized. Equity method investments, including their associated excess cost amounts, are evaluated for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is an other than temporary decline. The following table summarizes our excess cost information at June 30, 2004 by the business segment to which the unconsolidated affiliates relate:

			Initial Excess Cost attributable to				Unamortized balance at
	Amort. Periods		Tangible assets		Goodwill (1)		June 30, 2004
Fractionation segment:
Promix		20 years	$	7,955			$	5,802
La Porte		35 years		873				768
Pipelines segment:
GulfTerra GP (2)		n/a			$	328,214		328,214
Dixie		35 years		28,448		9,246		33,722
Neptune		35 years		12,768				11,492
Nemo		35 years		727				666
Tri-States (3)		35 years		3,628


(1)	Excess cost attributable to goodwill is not amortized; however, our investments in unconsolidated affiliates (which include excess cost amounts) are tested for impairment whenever events or circumstances indicate that there is a loss in value of the investment which is an other than temporary decline.
(2)	Reflects our preliminary allocation of GulfTerra GP’s $328.2 million of excess cost to goodwill.
(3)	Tri-States became a consolidated subsidiary of ours in April 2004.

The Pipelines section in the preceding table includes $337.5 million of excess cost attributable to goodwill, of which $328.2 million results from our December 2003 purchase of a 50% membership interest in GulfTerra GP. The allocation of the $328.2 million of excess cost to goodwill (which represents potential intangible assets, excess of fair values over carrying values of tangible assets and remaining goodwill, if any) is preliminary pending completion of a fair value analysis which is expected to be completed during the last half of 2004. The table below shows the potential decrease in equity earnings from GulfTerra GP if certain amounts included in this excess cost were ultimately assigned to tangible or amortizable intangible assets. For purposes of calculating this sensitivity, we have applied the straight-line method of cost allocation over an estimated useful life of 20-years to various fair values.

Amount allocated to Tangible or Amortizable Assets out of GulfTerra GP Excess Cost Goodwill	Excess Cost attributed to tangible or intangible assets	Estimated Annual Reduction in Equity Earnings from GulfTerra GP
20% of excess cost or $65.6 million	$ 65,643	$ 3,282
40% of excess cost or $131.3 million	131,286	6,564
60% of excess cost or $196.9 million	196,928	9,846
80% of excess cost or $262.6 million	262,571	13,129
100% of excess cost or $328.2 million	328,214	16,411

Expected change in accounting method for VESCO

As a result of newly issued accounting guidance per EITF 03-16, we changed our method of accounting for VESCO from the cost method to the equity method on July 1, 2004. The VESCO investment consists of a 13.1% membership interest in a limited liability company that owns a natural gas processing plant, NGL fractionation facilities, storage assets and gas gathering pipelines located in south Louisiana.

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

The following table summarizes our amortizable intangible assets at June 30, 2004:

	Gross Value		Accum. Amort.			Carrying Value
Shell natural gas processing agreement	$	206,216	$	(39,586	)	$	166,630
Mont Belvieu Storage II contracts		8,127		(581	)		7,546
Mont Belvieu Splitter III contracts		53,000		(3,660	)		49,340
Toca-Western natural gas processing contracts		11,187		(1,165	)		10,022
Toca-Western NGL fractionation contracts		20,042		(2,088	)		17,954
Venice contracts		6,635		(368	)		6,267
Port Neches pipeline contracts		2,400		(496	)		1,904
BEF UOP License Fee		1,657		(72	)		1,585

Total	$	309,264	$	(48,016	)	$	261,248

Goodwill

The following table summarizes our goodwill amounts at June 30, 2004 (excluding amounts included in the carrying value of unconsolidated affiliates – See Note 6).

	Segment Affiliation	Goodwill Balance
Splitter III acquisition (1)	Fractionation	$	73,690
MBA acquisition (2)	Fractionation		7,857
Wilprise acquisition (3)	Pipelines		880

		$	82,427


(1)	Amount recorded in connection with our acquisition of propylene fractionation assets from Diamond-Koch in February 2002.
(2)	Amount recorded in connection with our acquisition of an additional interest in Mont Belvieu Associates in July 2001, which owned an interest in our Mont Belvieu NGL fractionation facility.
(3)	Amount recorded in connection with our acquisition of an additional 37.4% in Wilprise in October 2003.

8. RELATED PARTY TRANSACTIONS

Relationship with EPCO

We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is one of our directors and Chairman of the Board of Directors. In addition, our executive and other officers are employees of EPCO, including O.S. Andras who is our President and Chief Executive Officer and one of our directors.

Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to the EPD units held by EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of members of Mr. Duncan’s family. EPCO and Dan Duncan LLC, together, own 100% of our membership interests. Collectively, EPCO, Dan L. Duncan, the Duncan Family 1998 Trust and the Duncan Family 2000 Trust owned 53.3% of EPD’s partnership interests at June 30, 2004 which includes our 2% ownership interest.

Our agreements with EPCO are not the result of arm’s-length transactions, and there can be no assurance that any of the transactions provided for therein are effected on terms at least as favorable to the parties to such agreement as could have been obtained from unaffiliated third parties.

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. Prior to January 1, 2004, we reimbursed EPCO for the costs of its employees who performed operating functions for us and for costs related to certain of its management and administrative personnel hired in response to the expansion of our business. In addition, we paid EPCO a monthly fee for services provided by its other management and administrative employees. On January 1, 2004, the Administrative Services Agreement was amended to eliminate the fee portion of this reimbursement and to provide that we reimburse EPCO for all such costs, including fringe benefits, related to management or administrative support for us.

We also have entered into an agreement with EPCO to provide trucking services to us for the transportation of NGLs and other products. In addition, we also buy from and sell to EPCO’s Canadian affiliate certain NGL products.

We are each separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. EPCO primarily depends on cash distributions it receives as an equity owner in EPD to fund EPCO’s other operations and to meet its debt obligations.

Relationship with Shell

We have a significant commercial relationship with Shell as a partner, customer and vendor. At June 30, 2004, Shell owned an approximate 16.9% equity interest in EPD. Shell is one of our largest customers. Our revenues from Shell primarily reflect the sale of NGL and petrochemical products to Shell and the fees we charge Shell for natural gas processing, pipeline transportation and NGL fractionation services. Our operating costs and expenses with Shell primarily reflect the payment of energy-related expenses related to the Shell natural gas processing agreement and the purchase of NGL products from Shell.

Relationship with unconsolidated affiliates

Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie and purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix.

9. MINORITY INTEREST AND MEMBERS’ EQUITY

Minority interest

Minority interest represents third-party unitholders’ and joint venture participants’ ownership interests in the net assets of certain of our subsidiaries. The following table shows the components of minority interest at June 30, 2004:

EPD’s limited partners:
Non-affiliates of EPGP Members	$	1,532,416
Affiliates of EPGP Members		460,095
Joint venture partners		88,823

	$	2,081,334

The minority interest attributable to EPD’s limited partners primarily consists of EPD common units held by the public, Shell and affiliates of EPGP. The minority interest attributable to joint venture partners is primarily attributable to our partners in Seminole, Wilprise, BEF and the Mid-America pipeline system. For financial reporting purposes, the assets and liabilities of our subsidiaries are consolidated with those of our own with any outside investor’s ownership interest in our consolidated balance sheet amounts shown as minority interest.

Members’ Equity

At June 30, 2004, DFI owned 95%, and Dan Duncan, LLC owned 5% of the membership interests of the Company. Earnings and cash distributions are allocated to Member capital accounts in accordance with their respective ownership percentages.

10. DEBT OBLIGATIONS

Our debt consisted of the following:

	June 30, 2004
Borrowings under:
Interim Term Loan, variable rate, repaid
in May 2004 (1)
364-Day Revolving Credit Facility, variable rate,
due October 2004, $230 million borrowing capacity
Multi-Year Revolving Credit Facility, variable rate,
due November 2005, $270 million borrowing capacity (2)	$	48,000
Senior Notes A, 8.25% fixed rate, due March 2005		350,000
Seminole Notes, 6.67% fixed rate, $15 million due
in December 2004 and 2005 (3)		30,000
MBFC Loan, 8.70% fixed rate, due March 2010		54,000
Senior Notes B, 7.50% fixed rate, due February 2011		450,000
Senior Notes C, 6.375% fixed rate, due February 2013		350,000
Senior Notes D, 6.875% fixed rate, due March 2033		500,000

Total principal amount		1,782,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,410
Unamortized balance of decrease in fair value related to
hedging a portion of fixed-rate debt		(10,146	)
Less unamortized discount on Senior Notes A, B, and D		(5,920	)

Subtotal long-term debt		1,767,344
Less current maturities of debt		(364,974	)

Long-term debt	$	1,402,370

Standby letters of credit outstanding, $75 million of
credit capacity available under our
Multi-Year Revolving Credit Facility	$	26,400


(1)	We used the proceeds from EPD’s May 2004 common unit offering to fully repay and terminate the Interim Term Loan.
(2)	This revolving credit facility has $270 million of total borrowing capacity, which is reduced by the amount of standby letters of credit outstanding.
(3)	Solely as it relates to the assets of our subsidiary, Seminole Pipeline Company, our $1.8 billion in senior indebtedness at June 30, 2004 is structurally subordinated and ranks junior in right of payment to the $30 million of indebtedness of Seminole Pipeline Company.

Scheduled future maturities of long-term debt. We have long and short-term payment obligations under credit agreements such as our Senior Notes and revolving credit facilities. Scheduled future maturities of debt obligations existing at June 30, 2004 were: $15 million due in 2004; $413 million due in 2005; $54 million due in 2010; $450 million due in 2011; $350 million due in 2013; and $500 million due in 2033. On May 5, 2004, we used $353.1 million in net proceeds from EPD’s May 2004 equity offering to repay the $225 million Interim Term Loan and approximately $128.1 million to temporarily reduce debt outstanding under our revolving credit facilities.

Parent-Subsidiary guarantor relationships. Through guarantor agreements which are nonrecourse to us, EPD acts as guarantor of the debt obligations of the Operating Partnership, with the exception of the Seminole Notes. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we owned an effective 88.4% of its capital stock at June 30, 2004).

Covenants. We were in compliance with the various covenants of our debt agreements at June 30, 2004.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable rate debt obligations during the six months ended June 30, 2004:

	Range of interest rates paid	Weighted- average interest rate paid
364-Day Revolving Credit Facility	1.72% to 4.00%	1.79%
Multi-Year Revolving Credit Facility	1.67% to 4.25%	1.71%
Interim Term Loan	1.72% to 1.78%	1.73%

11. FINANCIAL INSTRUMENTS

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. In general, the type of risks we attempt to hedge are those related to the variability of future earnings, cash flows and fair value of certain debt securities caused by changes in commodity prices and interest rates. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

We recognize our financial instruments on the balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.

Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in the Statement of Operations and Comprehensive Income for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses on a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

To qualify as a hedge, the item to be hedged must expose us to price risk, interest rate risk or changes in fair value and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is recorded into earnings immediately.

Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance about implementation issues. Since this guidance is still continuing, our conclusions regarding the application of guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of this guidance.

Interest rate risk hedging program

Our interest rate exposure results from variable and fixed rate borrowings under debt agreements (see Note 10). We assess the cash flow risk related to interest rates by identifying and measuring changes in our interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the expected impact of changes in interest rates on our future cash flows. Management oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.

We manage a portion of our interest rate risks by utilizing interest rate swaps and similar arrangements. The objective of entering into this type of arrangement is to manage debt service costs by converting a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. In general, an interest rate swap requires one party to pay a fixed interest rate on a defined (or “notional”) amount while the other party pays a variable rate based on the same notional amount. The notional amount specified in an interest rate swap agreement does not represent exposure to credit loss. We monitor our positions and the credit ratings of counterparties. Management believes the risk of incurring a credit loss on these financial instruments is remote, and that if incurred, such losses would be minimal. We believe that it is prudent to maintain an appropriate balance of variable rate and fixed rate debt.

Fair value hedges – Interest rate swaps. On January 8, 2004, we entered into three interest rate swap agreements under which we exchanged the payment of fixed rate interest on a portion of principal outstanding under Senior Notes B and C for variable rate interest:

Hedged Fixed Rate Debt	Period Covered by Swap	Termination Date of Swap	Fixed to Variable Rate (1)	Notional Amount
Senior Notes B, 7.50% fixed rate, due Feb.2011	Jan. 2004 to Feb.2011	Feb. 2011	7.50% to 4.6%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb.2013	Jan. 2004 to Feb.2013	Feb. 2013	6.375% to 3.1%	$100 million
Senior Notes C, 6.375% fixed rate, due Feb.2013	Jan. 2004 to Feb.2013	Feb. 2013	6.375% to 3.1%	$100 million


(1)	The variable rate indicated is the all-in variable rate for the current settlement period.

We have designated these interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. These agreements have a combined notional amount of $250 million and match the maturity dates of the underlying debt being hedged. Under the swap agreements, we pay the counterparty a variable rate based on six-month LIBOR (plus an applicable margin) and receive back from the counterparty a fixed rate payment equal to the stated interest rate of the debt being hedged, based on the notional amounts for each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”).

As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense. However, the interest rate swaps effectively converted a portion of the underlying fixed rate debt (i.e., the notional amounts hedged for Senior Notes B and C) into variable rate debt. As a result,

interest expense will vary depending on the variable rates payable by us under terms of the swap agreements at the end of each settlement period. To the extent that the variable rate amount payable by us at the end of each settlement period is less than the fixed rate amount receivable from the counterparty, we will amortize the difference ratably to earnings as a reduction in interest expense over the settlement period. If the variable rate payable by us at the end of each settlement period is more than the fixed rate amount receivable from the counterparty, we would amortize this difference ratably to earnings as an increase in interest expense over the settlement period.

Total fair value of the interest rate swaps at June 30, 2004 was a payable of approximately $10.1 million with an offsetting increase in fair value of the underlying debt. Interest expense in our Statements of Consolidated Operations and Comprehensive Income for the three and six months ended June 30, 2004 reflect a $2 million and $3.7 million benefit, respectively, from these swaps.

Cash flow hedges – Forward starting interest rate swaps. On March 17, 2004, we entered into four forward starting interest rate swap transactions with original maturities of September 30, 2004. A forward starting swap is an agreement that effectively hedges the price on a specific U.S. treasury security for an established period of time. The purpose of these transactions was to effectively hedge the underlying U.S. treasury interest rate associated with our anticipated issuance of fixed rate debt, the proceeds of which would be used (either separately or in combination) to finance the GulfTerra merger, to refinance debt initially incurred to complete the merger or to refinance the indebtedness of GulfTerra (see Note 3). The forward starting interest rate swaps have been designated as cash flow hedges under SFAS No. 133. The notional amount of the anticipated debt issuances is approximately $2 billion.

On April 23, 2004, we elected to terminate these financial instruments in order to monetize the then current value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. This amount will be amortized over the life of the anticipated debt (when issued) as a reduction to interest expense. The following table shows the portfolio of forward starting swaps categorized by the term of the underlying anticipated debt offering (Dollars in millions):

Term of Anticipated Debt Offering (or forecasted transaction)	Notional Amount of Anticipated Debt covered by Forward Starting Swaps			Cash Received upon Settlement of Forward Starting Swaps in April 2004
5-year, fixed rate debt instrument	$	500	.0	$	18	.7
10-year, fixed rate debt instrument		500	.0		26	.1
15-year, fixed rate debt instrument		500	.0		29	.4
30-year, fixed rate debt instrument		500	.0		30	.3

Total	$	2,000	.0	$	104	.5

The gain of $104.5 million in cash received was recorded as a component of AOCI in our Statement of Consolidated Partners’ Equity and as an addition to comprehensive income in our Statement of Consolidated Operations and Comprehensive Income for the three and six months ended June 30, 2004.

Commodity risk hedging program

The prices of natural gas, NGLs, petrochemical products and MTBE are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with our Processing segment activities, we may enter into various commodity financial instruments. The primary purpose of these risk management activities is to hedge our exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated transactions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

We do not hedge our exposure related to MTBE price risks. In addition, we generally do not hedge risks associated with the petrochemical marketing activities that are part of our Fractionation segment. In our Pipelines segment, we utilize a limited number of commodity financial instruments to manage the price Acadian Gas charges

certain of its customers for natural gas. Lastly, we do not employ commodity financial instruments in our fee-based marketing business classified under the Other segment.

We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by management. We enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. Management oversees our strategies associated with physical and financial risks (such as those mentioned previously), 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.

Our commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133 (as amended and interpreted). In those situations where the financial instrument does not qualify for hedge accounting treatment, the instrument is accounted for using mark-to-market accounting, which results in a degree of non-cash earnings volatility that is dependent upon changes in the commodity prices underlying these financial instruments. Even though these financial instruments may not qualify for hedge accounting treatment under SFAS No. 133, we view such contracts as hedges since this was the intent when we entered into such positions. Upon entering into such positions, our expectation is that the economic performance of these instruments will mitigate (or offset) the commodity risk being addressed. The specific accounting for these contracts; however, is consistent with the requirements of SFAS No. 133.

The fair value of our commodity financial instrument portfolio at June 30, 2004 and the results of our commodity hedging activities for the three and six months ended June 30, 2004 were both nominal amounts. During the first half of 2004, we utilized a limited number of commodity financial instruments.

12. SEGMENT INFORMATION

Operating segments are components of a business about which separate financial information is available. These components are regularly evaluated by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments.

We have five reportable business (or operating) segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. Our reportable segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the CEO of the General Partner. Pipelines consists of NGL, petrochemical and natural gas pipeline systems, storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization, and propylene fractionation services. Processing includes the natural gas processing business and its related NGL marketing activities. Octane Enhancement represents our investment in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE and isobutylene). The Other business segment consists of fee-based marketing services and various operational support activities.

Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling item between consolidated property, plant and equipment and segment property is construction-in-progress. Segment property represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not generally contribute to segment gross operating margin, these assets are not included in the operating segment totals until they are deemed operational. Consolidated intangible assets and goodwill are allocated to the segments based on the classification of the assets to which they relate.

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

	Operating Segments										Adjs.
	Fractionation		Pipelines		Processing		Octane Enhancement		Other		and Elims.		Consol. Totals
Segment assets:
At June 30, 2004	$	468,468	$	2,249,678	$	210,353	$	37,553	$	13,738	$	41,029	$	3,020,819

Investments in and advances to
unconsolidated affiliates (see Note 6):
At June 30, 2004		87,675		598,030		33,000								718,705

Intangible Assets (see Note 7):
At June 30, 2004		67,294		9,450		182,919		1,585						261,248

Goodwill (see Note 7):
At June 30, 2004		81,547		880										82,427

13. SUBSEQUENT EVENTS

August 2004 equity offering

In August 2004, EPD sold 17,250,000 common units to the public at an offering price of $20.20 per unit. Net proceeds from this offering, including our proportionate net capital contribution of $6.8 million, were approximately $341.4 million after deducting applicable underwriting discounts, commissions and offering expenses of $14.2 million. We used $210 million of the net proceeds from this offering to temporarily reduce borrowings under our Multi-Year Revolving Credit Facility. The remaining proceeds of approximately $130 million will be used to fund a portion of our payment obligations to El Paso under Step Two of the proposed merger, or, if the proposed merger with GulfTerra (see Note 3) does not close, for working capital purposes or for future acquisitions.