8-K/A

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 8-K/A

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 17, 2004

SOUTHERN UNION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	1-6407	75-0571592
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)

One PEI Center	18711
Wilkes-Barre, Pennsylvania (Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (570) 820-2400

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ]	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
[ ]	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 2.01 COMPLETION OF ACQUISITION OR DISPOSITION OF ASSETS

On November 17, 2004, CCE Holdings, LLC (“CCE Holdings”), a joint venture between subsidiaries of Southern Union Company (“Southern Union”) and General Electric Commercial Finance Energy Financial Services (“GE”), completed its acquisition of 100% of the interests of CrossCountry Energy, LLC (“CrossCountry”) from Enron Corp. and its affiliates (the “CrossCountry Acquisition”).

The primary subsidiaries of CrossCountry are Transwestern Holding Company, Inc. (“TW Holdings”), CrossCountry Citrus Corp. (“CrossCountry Citrus”), CrossCountry Energy Services, LLC (“Services”), Northern Plains Natural Gas Company (“Northern Plains NG”), and NBP Services Corporation (“NBP Services”, together with Northern Plains NG, “Northern Plains”), all of which were wholly-owned and contributed by Enron to CrossCountry on March 31, 2004. The primary assets of TW Holdings and CrossCountry Citrus are their investments in pipeline companies, Transwestern Pipeline Company (“TWP”) and Citrus Corp. (50% owned by CrossCountry Citrus), respectively. Citrus Corp. owns 100% of Florida Gas Transmission Company.

Pursuant to an agreement with ONEOK, Inc. (“ONEOK”) and concurrent with the CrossCountry Acquisition, CCE Holdings sold its interest in Northern Plains for $175 million. Because Northern Plains is no longer a part of CrossCountry, the historical results of Northern Plains are not material to an understanding of the future operations of CCE Holdings and, therefore, are not presented. The allocation of the purchase price to CrossCountry’s interest in Northern Plains was equivalent to the sales proceeds of $175 million. Accordingly, no gain or loss was recognized on the sale. Additionally, substantially all of the expenses of Services were billed to, and were incurred on behalf of, TWP, Citrus Corp. and Northern Plains, and Services had no material revenues other than billings at cost to CrossCountry’s pipeline businesses. Accordingly, the net results of Services are embedded in the stand-alone results of TWP, Citrus Corp. and Northern Plains and are not presented separately. Furthermore, because certain CrossCountry employees have been transferred or terminated in connection with the sale of Northern Plains, the costs incurred by Services attributable to Northern Plains are not expected to be incurred by CCE Holdings in the future. During the year ended December 31, 2003, Services billed $10.2 million, $11.6 million and $3.3 million to TWP, Citrus and Northern Plains, respectively, for administrative services. For the nine months ended September 30, 2004, Services billed $7.0 million, $10.2 million and $3.6 million to TWP, Citrus Corp. and Northern Plains, respectively, for administrative services.

In connection with the above-mentioned transaction, certain audited historical financial statements and related notes thereto of TWP and Citrus Corp. for the year ended December 31, 2003 are attached hereto as Exhibits to this Current Report on Form 8-K/A. The Exhibits also include the unaudited historical financial statements and related notes of TWP and Citrus Corp. for the nine months ended September 30, 2004 and 2003.

The unaudited pro forma consolidated condensed financial statements attached hereto as Exhibit 99.f to this Current Report on Form 8-K/A present the consolidated financial data of Southern Union and its subsidiaries, after giving effect to Southern Union’s investment to acquire a 50% interest in CCE Holdings, and CCE Holdings’ acquisition of CrossCountry as further described in Exhibit 99.f.

ITEM 9.01      FINANCIAL STATEMENTS AND EXHIBITS

(a)Financial Statements.

The following financial statements omitted from Southern Union’s Current Report on Form 8-K with respect to the event dated November 17, 2004 filed with the U.S. Securities and Exchange Commission ("Commission") on November 22, 2004 in reliance upon Item 9.01(a)(4) of Form 8-K are filed herewith:

(1)Audited restated historical financial statements and related notes of Transwestern Pipeline Company for the year ended December 31, 2003 (Exhibit 99.b).

(2)Audited historical financial statements and related notes of Citrus Corp. and Subsidiaries for the year ended December 31, 2003 (Exhibit 99.c).

(3)Unaudited historical financial statements and related notes of Transwestern Pipeline Company for the nine months ended September 30, 2004 and 2003 (Exhibit 99.d).

(4)Unaudited historical financial statements and related notes of Citrus Corp. and Subsidiaries for the nine months ended September 30, 2004 and 2003 (Exhibit 99.e).

(b)Pro Forma Financial Information.

The following pro forma financial information omitted from Southern Union’s Current Report on Form 8-K with respect to the event dated November 17, 2004 filed with the Commission on November 22, 2004 in reliance upon Item 9.01(b)(2) of Form 8-K are filed herewith:

(1)Unaudited Pro Forma Consolidated Condensed Financial Statements of Southern Union Company and its subsidiaries, and related Notes thereto (Exhibit 99.f).

(c)     Exhibits.

2.a	Purchase Agreement Among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, L.L.C., and Enron Corp., dated as of June 24, 2004. (Filed as Exhibit 99.b to Southern Union's Current Report on Form 8-K filed on June 25, 2004 and incorporated herein by reference.)
2.b	Amendment No. 1 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated September 1, 2004. (Filed as Exhibit 10.a to Southern Union's Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)
2.c	Amendment No. 2 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated November 10, 2004. (Filed as Exhibit 2.c to Southern Union's Current Report on Form 8-K filed on November 22, 2004 and incorporated herein by reference.)
2.d	Purchase Agreement between CCE Holdings, LLC and ONEOK, Inc. dated September 16, 2004. (Filed as Exhibit 10.a to Southern Union's Current Report on Form 8-K filed on September 17, 2004 and incorporated herein by reference.)
23.a	Consent of PricewaterhouseCoopers LLP.
23.b	Consent of PricewaterhouseCoopers LLP.
99.a	Press Release issued by Southern Union dated November 17, 2004. (Filed as Exhibit 99.a to Southern Union's Current Report on Form 8-K filed on November 22, 2004 and incorporated herein by reference.)
99.b	Audited restated historical financial statements and related notes of Transwestern Pipeline Company for the year ended December 31, 2003.
99.c	Audited historical financial statements and related notes of Citrus Corp. and Subsidiaries for the year ended December 31, 2003.
99.d	Unaudited historical financial statements and related notes of Transwestern Pipeline Company for the nine months ended September 30, 2004 and 2003.
99.e	Unaudited historical financial statements and related notes of Citrus Corp. and Subsidiaries for the nine months ended September 30, 2004 and 2003.
99.f	Unaudited Pro Forma Consolidated Condensed Financial Statements of Southern Union Company and its subsidiaries, and related Notes thereto.

This release and other reports and statements issued or made from time to time contain certain "forward-looking statements" concerning projected future financial performance, expected plans or future operations. Southern Union cautions that actual results and developments may differ materially from such projections or expectations.

Investors should be aware of important factors that could cause actual results to differ materially from the forward-looking projections or expectations. These factors include, but are not limited to: cost of gas; gas sales volumes; gas throughput volumes and available sources of natural gas; discounting of transportation rates due to competition; customer growth; abnormal weather conditions in Southern Union’s service territories; impact of relations with labor unions of bargaining-unit employees; the receipt of timely and adequate rate relief and the impact of future rate cases or regulatory rulings; the outcome of pending and future litigation; the speed and degree to which competition is introduced to Southern Union’s gas distribution business; new legislation and government regulations and proceedings affecting or involving Southern Union; unanticipated environmental liabilities; ability to comply with or to challenge successfully existing or new environmental regulations; changes in business strategy and the success of new business ventures, including the risks that the business acquired and any other businesses or investments that Southern Union has acquired or may acquire may not be successfully integrated with the business of Southern Union; exposure to customer concentration with a significant portion of revenues realized from a relatively small number of customers and any credit risks associated with the financial position of those customers; factors affecting operations such as maintenance or repairs, environmental incidents or gas pipeline system constraints; Southern Union’s, or any of its subsidiaries, debt securities ratings; the economic climate and growth in the energy industry and service territories and competitive conditions of energy markets in general; inflationary trends; changes in gas or other energy market commodity prices and interest rates; the current market conditions causing more customer contracts to be of shorter duration, which may increase revenue volatility; the possibility of war or terrorist attacks; the nature and impact of any extraordinary transactions such as any acquisition or divestiture of a business unit or any assets.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		SOUTHERN UNION COMPANY
		(Registrant)
Date: February 1, 2005	By	/s/ DAVID J. KVAPIL
		David J. Kvapil
		Executive Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit Number Description

2.a	Purchase Agreement Among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, L.L.C., and Enron Corp., dated as of June 24, 2004. (Filed as Exhibit 99.b to Southern Union's Current Report on Form 8-K filed on June 25, 2004 and incorporated herein by reference.)
2.b	Amendment No. 1 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated September 1, 2004. (Filed as Exhibit 10.a to Southern Union's Current Report on Form 8-K filed on September 14, 2004 and incorporated herein by reference.)
2.c	Amendment No. 2 to Purchase Agreement by and among CCE Holdings, LLC, Enron Operations Services, LLC, Enron Transportation Services, LLC, EOC Preferred, LLC, and Enron Corp., dated November 10, 2004. (Filed as Exhibit 2.c to Southern Union's Current Report on Form 8-K filed on November 22, 2004 and incorporated herein by reference.)
2.d	Purchase Agreement between CCE Holdings, LLC and ONEOK, Inc. dated September 16, 2004. (Filed as Exhibit 10.a to Southern Union's Current Report on Form 8-K filed on September 17, 2004 and incorporated herein by reference.)
23.a	Consent of PricewaterhouseCoopers LLP.
23.b	Consent of PricewaterhouseCoopers LLP.
99.a	Press Release issued by Southern Union dated November 17, 2004. (Filed as Exhibit 99.a to Southern Union's Current Report on Form 8-K filed on November 22, 2004 and incorporated herein by reference.)
99.b	Audited restated historical financial statements and related notes of Transwestern Pipeline Company for the year ended December 31, 2003.
99.c	Audited historical financial statements and related notes of Citrus Corp. and Subsidiaries for the year ended December 31, 2003.
99.d	Unaudited historical financial statements and related notes of Transwestern Pipeline Company for the nine months ended September 30, 2004 and 2003.
99.e	Unaudited historical financial statements and related notes of Citrus Corp. and Subsidiaries for the nine months ended September 30, 2004 and 2003.
99.f	Unaudited Pro Forma Consolidated Condensed Financial Statements of Southern Union Company and its subsidiaries, and related Notes thereto.

EX-23.A

   EXHBIT 23.a

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-113757) and Form S-8 (File Nos. 33-37261, 33-69596, 33-69598, 33-61558, 333-79443, 333-08994, 333-42635, 333-89971, 333-36146, 333-36150, 333-47144 and 333-112527) of Southern Union Company, of our report dated February 1, 2005 relating to the financial statements of Transwestern Pipeline Company, which appears in the Current Report on Form 8-K/A of Southern Union Company dated November 17, 2004.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 1, 2005

EX-23.B

EXHIBIT 23.b

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-113757) and Form S-8 (File Nos. 33-37261, 33-69596, 33-69598, 33-61558, 333-79443, 333-08994, 333-42635, 333-89971, 333-36146, 333-36150, 333-47144 and 333-112527) of Southern Union Company, of our report dated March 24, 2004 relating to the consolidated financial statements of Citrus Corp. and Subsidiaries, which appears in the Current Report on Form 8-K/A of Southern Union Company dated November 17, 2004.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

January 31, 2005

EX-99.B

EXHIBIT 99.b

Report of Independent Auditors

To the Board of Directors and Stockholder of Transwestern Pipeline Company:

In our opinion, the accompanying balance sheetand the related statements of operations, stockholder’s equity and cash flows present fairly, in all material respects, the financial position of Transwestern Pipeline Company (the Company) atDecember 31, 2003, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Note 1, the Company has restated its financial statements, which were previously audited by other independent auditors, for the year ended December 31, 2003.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 1, 2005

EXHIBIT 99.b

TRANSWESTERN PIPELINE COMPANY
BALANCE SHEET
(In Thousands)
	December 31,
	2003
	(Restated)
ASSETS
Current Assets
Cash and cash equivalents	$	20,557
Accounts receivable - customers, net of allowance of $127		15,838
Transportation and exchange gas receivable		3,370
Regulatory assets		6,692
Other		5,960
Total Current Assets		52,417
Property, Plant and Equipment, at Cost		1,067,854
Less - Accumulated depreciation and amortization		(138,759	)
Property, Plant and Equipment, Net		929,095
Other Assets
Deferred income taxes		26,637
Regulatory assets		62,313
Other		26,175
Total Other Assets		115,125
Total Assets	$	1,096,637

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
BALANCE SHEET
(In Thousands, Except Share Data)
	December 31,
	2003
	(Restated)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable
Trade and other	$	2,835
Associated companies		9,618
Transportation and exchange gas payable		5,933
Notes payable and current maturities of long-term debt		461,000
Accrued taxes, other than income		5,775
Accrued interest		1,358
Deferred revenue		3,854
Reserve for regulatory and other contingencies		2,682
Other		3,309
Total Current Liabilities		496,364
Deferred Credits and Other Liabilities
Other		4,715
Total Deferred Credits and Other Liabilities		4,715
Commitments and Contingencies (Note 8)		-
Stockholder’s Equity
Common stock ($1 par value; 1,000 shares authorized, issued and outstanding)		1
Additional paid-in capital		409,191
Retained earnings		186,366
Total Stockholder’s Equity		595,558
Total Liabilities and Stockholder’s Equity	$	1,096,637

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
STATEMENT OF OPERATIONS
(In Thousands)
		Year Ended
		December 31,
		2003
		(Restated)
Revenues
Transportation	$	178,298
Gas and liquids sold		20,831
Other gas revenues		294
Total Revenues		199,423
Costs and Expenses
Operating and maintenance expenses		60,138
Amortization of regulatory assets		4,631
Depreciation and amortization		24,007
Taxes, other than income taxes		10,908
Total Costs and Expenses		99,684
Operating Income		99,739
Other Income (Expense)
Interest income		419
Interest expense and related charges, net		(38,246	)
Other, net		2,468
Total Other Income (Expense)		(35,359	)
Income Before Income Taxes		64,380
Income Taxes		25,292
Net Income	$	39,088

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
STATEMENT OF STOCKHOLDER’S EQUITY
(In Thousands)
		December 31,
		2003
		(Restated)
Common Stock
Balance, beginning and end of year	$	1
Additional Paid-in Capital
Balance, beginning and end of year		409,191
Retained Earnings
Balance, beginning of year		147,278
Net income		39,088
Balance, end of year		186,366
Total Stockholder’s Equity	$	595,558

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
STATEMENT OF CASH FLOWS
(In Thousands)
		Year Ended
		December 31,
		2003
		(Restated)
Cash Flows From Operating Activities
Adjustments to reconcile net income to net cash provided by operating activities:
Net income	$	39,088
Depreciation and amortization		24,007
Amortization of regulatory assets, non-current		5,643
Other assets and liabilities, non-cash adjustments		(2,203	)
Amortization of debt costs		10,894
Deferred income taxes		25,780
Changes in operating assets and liabilities:
Receivables		1,730
Payables		(4,878	)
Deferred revenue		445
Regulatory and other contingency adjustments		(11,483	)
Other current assets / liabilities		(3,588	)
Cash Provided by Operating Activities		85,435
Cash Flows From Investing Activities
Additions to property, plant and equipment		(17,095	)
Other capital expenditures		(542	)
Cash Used in Investing Activities		(17,637	)
Cash Flows From Financing Activities
Repayment of debt		(84,000	)
Debt issuance costs on debt		(3,167	)
Cash Used in Financing Activities		(87,167	)
Decrease in Cash and Cash Equivalents		(19,369	)
Cash and Cash Equivalents, Beginning of Year		39,926
Cash and Cash Equivalents, End of Year	$	20,557
Supplemental Disclosure of Cash Flow Information
Interest paid	$	26,163

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

(1) Nature of Operations and Summary of Significant Accounting Policies

At December 31, 2003, Transwestern Pipeline Company (Transwestern) was a wholly owned subsidiary of Transwestern Holding Company, Inc. (TW Holdings). TW Holdings owned directly 80 percent of the equity of Transwestern, and owned the remaining 20 percent beneficial interest in Transwestern through a voting trust described below (see Note 3). Effective March 31, 2004, pursuant to its plan of reorganization filed with the United States Bankruptcy Court in the Southern District of New York (Bankruptcy Court), Enron Corp. (Enron) and certain of its subsidiaries transferred their interests in TW Holdings, among other assets, to CrossCountry Energy, LLC (CrossCountry), which at the time was a wholly owned subsidiary of Enron. Effective November 17, 2004, CrossCountry became a wholly owned subsidiary of CCE Holdings, L LC (CCE Holdings), which is a joint venture currently owned by subsidiaries of Southern Union Company (Southern Union)(50 percent), GE Commercial Finance Energy Financial Services (GE)(30 percent) and four minority interest owners (20 percent in the aggregate) (see Note 10). All of the voting interests in CCE Holdings are owned by Southern Union and GE. Also, on or about November 17, 2004, Transwestern and certain other affiliated entities were converted to limited liability companies. Transwestern owns and operates approximately 2,400 miles of interstate natural gas pipeline system extending from Texas and Oklahoma, through the San Juan Basin to the California border. Transwestern is a major natural gas transporter to the California border, and delivers natural gas from the east end of its system to Texas intrastate and Midwest markets.

Restatement of Financial Statements

The accompanying financial statements have been restated since their original issuance to: (i) correct an error in the adoption of the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets,” (SFAS No. 142);  (ii) report the write-off of deferred compressor overhaul expenditures as operating and maintenance expenses, rather than as a cumulative effect of a change in accounting principle; and (iii) correct an error in the accounting for deferred taxes under SFAS No. 109, “Accounting for Income Taxes.”

In connection with adopting SFAS No. 142, effective January 1, 2002, Transwestern reclassified to goodwill a net amount of $191.2 million, and ceased amortization of this amount on a prospective basis. The reclassification to goodwill was composed of $438.8 million of excess acquisition cost over the historical net book value of Transwestern’s net assets (the Acquisition Adjustment) that arose from Enron’s acquisition of Transwestern in 1984, less the accumulated amortization and deferred tax liability. The impact of the reclassification at January 1, 2002 was a decrease in property, plant and equipment of $76.0 million, an increase in accumulated depreciation and amortization of $218.1 million and a decrease in deferred tax liability of $102.9 million. Until January 1, 2002, Transwestern reported the Acquisition Adjustment as a component of property, plant and equipment, amortized it over a life consistent with its pipeline assets, ranging from 40 to 57 years, and recorded the related deferred tax liability. Upon reevaluating the appropriate accounting and transition provisions of SFAS No. 142, Transwestern determined that the January 1, 2002 reclassification of amounts to goodwill was an error. The impact on the 2003 financial statements of correcting that error results in: (i) a decrease in beginning retained earnings of $3.9 million; (ii) an increase in net property, plant and equipment of $282.2 million; (iii) a decrease in goodwill of $191.2 million; (iv) an increase in deferred income tax liabilities of $98.8 million; and (v) an increase in net loss of $3.9 million.

Transwestern has also restated its statement of operations for the year ended December 31, 2003 to report its write-off of previously deferred costs associated with compressor overhaul expenditures as a component of operating and maintenance expenses, rather than as a cumulative effect of a change in accounting principle. These costs had been deferred in previous periods under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” During 2003, at the time such costs no longer met the criteria under SFAS No. 71 for deferral, they should have been charged directly to expense and not reported as a change in accounting principle. The impact of this restatement is an increase in operating and maintenance expenses of $2.7 million and a decrease in income taxes of $1.1 mi llion. There is no change in Transwestern’s net loss as a result of this restatement.

The financial statements have also been restated to correct the misapplication of SFAS No. 109 in determining the realizability of deferred tax assets. Transwestern previously provided a $23.3 million valuation allowance during 2002 against its NOLs and provided an additional $102.3 million valuation allowance during 2003. Management believed that Enron's potential near-term sale of Transwestern indicated that Transwestern's NOLs, computed on a separate-return basis, would not be utilized by Transwestern prior to its disposition. However, based on an evaluation of expected future taxable income of Transwestern, as a stand-alone taxpayer on a going-concern basis, the appropriate accounting is that such deferred tax assets were fully realizable.  The impact on the 2003 financial statements of c orrecting that error results in: (i) an increase in beginning retained earnings of $23.3 million; (ii) an increase in net deferred tax assets as of December 31, 2003 of $102.3 million; and (iii) a decrease in income tax expense of $102.3 million with a corresponding effect on net income (loss).   There is no change in Transwestern’s net cash from operating, investing or financing activities as a result of this restatement. Furthermore, Transwestern has reclassified in its 2003 balance sheet $91.2 million from receivable from parent to net deferred tax assets.

A summary of the effects of the restatements and reclassifications noted above on previously reported amounts as of and for the year ended December 31, 2003 is presented below.

	As of and for the Year Ended December 31, 2003
	As Reported			As Restated
Income Statement
Operating and maintenance expenses	$	57,435		$	60,138
Depreciation and amortization		18,007			24,007
Total costs and expenses		90,981			99,684
Operating income		108,442			99,739
Income before taxes and cumulative effect of change in accounting principle		73,083			64,380
Income tax expense		130,744			25,292
Income (loss) before cumulative effect of change in accounting principle		(57,661	)		39,088
Cumulative effect of change in accounting principle, net of taxes		1,652			-
Net income (loss)		(59,313	)		39,088
Balance Sheet
Property, plant and equipment, at cost	$	991,830		$	1,067,854
Accumulated depreciation and amortization		(344,904	)		(138,759	)
Property, plant and equipment, net		646,926			929,095
Goodwill		191,215			-
Deferred income tax assets		-			26,637
Total assets		1,070,226			1,096,637
Deferred income tax liabilities		91,386			-
Retained earnings		68,569			186,366
Stockholder’s equity		477,761			595,558
Total liabilities and stockholder’s equity		1,070,226			1,096,637
Statement of Stockholder’s Equity
Beginning retained earnings	$	127,882		$	147,278
Net income (loss)		(59,313	)		39,088
Stockholder’s equity		477,761			595,558
Statement of Cash Flows
Net income (loss)	$	(59,313	)	$	39,088
Depreciation and amortization		18,007			24,007
Other assets and liabilities, non-cash adjustments		(4,906	)		(2,203	)
Deferred income taxes		149,951			25,780
Tax receivable from parent		(18,719	)		-

 

The accompanying notes are an integral part of these financial statements.

Regulatory Accounting

Transwestern is subject to regulation by the Federal Energy Regulatory Commission (FERC). Transwestern’s accounting policies generally conform to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under U.S. generally accepted accounting principles for nonregulated entities (see Notes 7 and 8).

Revenue Recognition

Revenues consist primarily of fees earned from natural gas transportation services. Reservation revenues on firm contracted capacity are recognized ratably over the contract period. For interruptible or volumetric-based services, revenues are recorded upon the delivery of natural gas to the agreed upon redelivery point. Revenues for all services are generally based on the heating value, denominated in British thermal units of gas delivered or subscribed, at a rate specified in the contract. Recognition of revenues received in advance of delivery of natural gas is deferred until the gas is delivered (see Note 5).

Transwestern is subject to FERC regulations and, as a result, revenues collected during the pendency of a rate proceeding may be required by FERC to be refunded in a final order. Transwestern establishes reserves for these potential refunds, as appropriate. There were no such reserves at December 31, 2003.

Derivative Instruments

Transwestern may engage in price risk management activities and accounts for these under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS No. 133, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless the derivatives qualify and are designated as hedges of future cash flows, fair values, net investments or qualify and are designated as normal purchases and sales. For derivatives treated as hedges of future cash flows, the effective portion of changes in fair value is recorded in other comprehensive income until the related hedged items impact earnings. Any ineffective portion of a hedge is reported in earnings immediately. Derivatives designated as normal purchases or sales are recorded and recognized in income using accrual accounting.

During 2003, Transwestern’s commercial contracts were designated normal purchases or normal sales. The contract types designated as normal include: (i) transportation; (ii) purchases of materials and services; (iii) system balancing agreements and third party storage; (iv) operational balancing agreements; and (v) operational gas purchases and sales.

Property, Plant and Equipment

Property, plant and equipment is recorded at its original cost of construction or acquisition. Transwestern capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest associated with capital projects. The cost of repairs is charged to operating and maintenance expenses. Costs of extensions, replacements and renewals of units of property are capitalized. The original cost of property retired is charged to accumulated depreciation and amortization, net of salvage and removal costs. No retirement gain or loss is included in the results of operations except in the case of sales or retirements of operating units.

The provision for depreciation and amortization is computed using the straight-line method based on estimated economic or FERC mandated lives. Transwestern’s composite depreciation rates, ranging generally from 1.2 percent to 10.0 percent, are applied to the FERC functional groups of gross property having similar economic characteristics. Transmission Plant is depreciated at 1.2 percent per year. General Plant is depreciated at 10 percent per year. Intangible Assets are depreciated over lives ranging from 2 to 12 years. The acquisition adjustment is depreciated over the estimated life of the pipeline assets, or approximately 1.4 percent per year.

Impairment losses are recognized for long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying value. The amount of impairment is measured by comparing the fair value of the asset to its carrying amount.

An accrual of allowance for funds used during construction (AFUDC) is a utility accounting practice calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of servicing the capital invested in construction work-in-progress. AFUDC has been segregated into two component parts - borrowed funds and equity funds. The allowance for borrowed and equity funds used during construction totaled $0.1 million during 2003, and is included in Other Income in the accompanying Statement of Operations.

Compressor Overhaul Expenses

During 2003, Transwestern began to expense its compressor overhaul costs in the period incurred as management determined that the deferral of such costs no longer qualified as an asset in accordance with SFAS No. 71. The deferred costs at January 1, 2003 totaling $2.7 million were charged to operating and maintenance expenses in 2003. Overhaul expenses incurred during 2003 totaled $0.9 million.

Transportation and Exchange Gas Imbalances, Net

Natural gas imbalances occur as a result of differences in volumes of gas received and delivered. Transwestern recordsnatural gas imbalance in-kind receivables and payables at the dollar weighted composite average of all current month gas transactions.The imbalances are settled periodically at the request of the party that is owed natural gas. Upon the requested settlement date, the party that owes the natural gas will settle the imbalance, based on the applicable transportation agreement, by either: (i) delivering the required physical volume of natural gas, or; (ii)paying a cumulative dollar value amount as calculated per the operator balancing agreement.

Computer Software

Transwestern’s accounting policy for the costs of computer software (all of which is for internal use only) is to capitalize direct costs of materials and services consumed in developing or obtaining software, including payroll and payroll-related costs for employees who are directly associated with and who devote time to the software project. Costs may begin to be capitalized once the application development stage has begun. All other costs are expensed as incurred. Transwestern amortizes the costs at a rate of 10 percent per year. Impairment is evaluated based on changes in the expected usefulness of the software. Transwestern has capitalized software costs, net of amortization, of $4.1 million at December 31, 2003. Computer software is included in Property Plant and Equipment under Intangible Assets (see Note 4).

Environmental Expenditures

Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Environmental expenditures relating to current or future revenues are expensed or capitalized as appropriate based on the nature of the costs incurred. Liabilities are recorded when environmental assessments and/or clean ups are probable and the costs can be reasonably estimated (see Note 8).

Cash and Cash Equivalents

Transwestern’s cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.

Intangible Assets

Intangible assets, none of which include goodwill, are recorded at fair value and are amortized to expense over their estimated useful lives. Intangible assets are presented as a component of Property, Plant and Equipment (see Note 4).

Intangible assets with indefinite useful lives are not amortized to expense, but are reviewed for impairment annually and whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If the fair value exceeds its carrying value, then the asset is not impaired. If its carrying value exceeds its implied fair value, then an impairment loss equal to the excess is recognized. No impairments of intangible assets were recognized during 2003.

System Gas

Transwestern accounts for system balancing gas using the fixed asset accounting model established under FERC Order No. 581. Under this approach, system gas volumes are classified as fixed assets and valued at historical cost. Encroachments upon system gas are valued at current market prices. Transwestern may sell system gas in excess of its system operational requirements.

Income Taxes

Transwestern accounts for income taxes under the provisions of SFAS No. 109, “Accounting for Income Taxes,” which provides for an asset and liability approach to accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (see Note 2).

Recent Accounting Pronouncements

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement requires companies to record a liability for the estimated removal costs of assets used in their business where there is a legal obligation associated with removal. The liability is recorded at its fair value, with a corresponding asset that is depreciated over the remaining useful life of the long-lived asset to which the liability relates. An ongoing expense will also be recognized for changes in the value of the liability as a result of the passage of time. The provisions of SFAS No. 143 are effective for fiscal years beginning after June 15, 2002. Transwestern adopted SFAS No. 143, beginning January 1, 2003. A comprehensive study was made in 2003 by the Company’s Accounting, Right of Way, Legal, Internal Audit, and Operations personnel to identify all Asset Retirement Obligations that are estimable as defined in SFAS No. 143, and it has been determined that the adoption of this standard did not have a financial statement impact at this time. Transwestern will continue to monitor these requirements on an annual basis in the future.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” This statement will require recognition of costs associated with exit or disposal activities when they are incurred rather than when a commitment is made to an exit or disposal plan. Examples of costs covered by this guidance include lease termination costs, employee severance costs associated with a restructuring, discontinued operations, plant closings or other exit or disposal activities. This statement is effective for fiscal years beginning after December 31, 2002, and will impact any exit or disposal activities initiated after January 1, 2003. SFAS No. 146 has not had an impact on Transwestern’s financial position or results of operations.

On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was signed. The Act raises a number of issues with respect to accounting for income taxes. On December 21, 2004, the FASB issued a FASB Staff Position (FSP) regarding the accounting implications of the Act related to the deduction for qualified domestic production activities (FSP FAS 109-1). The guidance in the FSP applies to financial statements for periods ending after the date the Act was enacted.

In FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the FASB decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under SFAS No. 109, “Accounting for Income Taxes,” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. In most cases, a company’s existing deferred tax balances will not be impacted at the date of enactment. For some companies, the deduction could have an impact on their effective tax rate and, therefore, should be considered when determining the estimated annual rate used for interim financial reporting. Transwestern is currently evaluating the impact, if any, of this FSP on its financial statements.

In SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” the FASB modified the existing guidance on accounting for nonmonetary transactions in Accounting Principles Board Opinion No. 29, “Accounting for Nonmonetary Transactions,” to eliminate an exception under which certain exchanges of similar productive nonmonetary assets were not accounted for at fair value. SFAS No. 153 instead provides a general exception for exchanges of nonmonetary assets that do not have commercial substance. This statement must be applied to nonmonetary assets exchanges occurring in fiscal periods beginning after June 15, 2005. Transwestern is currently evaluating the impact, if any, of this statement on its financial statements.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(2) Income Taxes

Tax Agreements

At December 31, 2003, Transwestern was included in the consolidated federal and state income tax returns filed by Enron. Transwestern calculates tax expense on a “separate return basis”, which requires the Company to present current and deferred taxes as if it were a separate taxpayer. Transwestern is party to a Tax Sharing Agreement dated March 31, 2004 (the “2004 Agreement”) and  the 1994 Transwestern Tax Allocation Agreement with Enron (the “1994 Agreement”), for the purpose of apportioning and allocating tax liabilities and deductions among the Enron consolidated group of companies.  The 2004 Agreement also preserved the ability of Transwestern to settle certain amounts for which Enron previously recognized the benefit in its consolidated tax return under the terms of the 1994 Agreement. Such settlement amount is reduced by Transwestern’s generation of current tax expense in periods subsequent to December 31, 2002 and would require settlement immediately prior to Transwestern ceasing to be a member of the Enron consolidated return. No such settlement resulting in a payment from Enron to Transwestern would be effected without prior consent of the Official Committee of Unsecured Creditors of Enron Corp. or any other committee, if any, whether formed pursuant to the Joint Plan of Reorganization of Enron Corp. and its affiliated debtors, as may be amended and supplemented from time to time or otherwise, as a successor to the Committee to represent the interests of the unsecured creditors of Enron in the Chapter 11 cases commenced by Enron and certain of its direct and indirect subsidiaries on or after December 2, 2001. In connection with the CrossCountry Acquisition effective November 17, 2004, the 2004 and 1994 Agreements were terminated and Enron paid $62.5 million to Transwestern in settlement of Transwestern’s rights accumulated under the 1994 Agreement.

Transwestern, as a member of the Enron consolidated tax group, was potentially severally liable for the tax liability of the consolidated group for the years that Transwestern was a member of the group pursuant to Treasury regulation §1.1502-6. Management believes that the Transwestern exposure to Enron’s consolidated tax liability is limited, in part because at the closing of the Purchase Agreement (see Note 10) on November 17, 2004, Transwestern, CrossCountry and the other members of the CrossCountry group were indemnified and held harmless by Enron for any federal or state income tax liabilities in excess of $5.7 million arising from Treasury regulations §1.1502-6.

Net Operating Losses

As of December 31, 2003, Transwestern had accumulated a net operating loss (NOL) totaling $216.8 million. This NOL expires in 2022 and has been calculated based on a separate return basis. No valuation allowance is considered necessary by management given the expected taxable income of Transwestern in future periods.  However, this NOL carryforward, computed on a separate-return basis, would not be available to any successor entity once Transwestern exits the Enron consolidated tax return.

Deferred Taxes

The principal components of Transwestern's net deferred income taxes at December 31, 2003, are as follows (in thousands):

Deferred income tax assets
Regulatory and other reserves	$	4,574
Bad debt reserve		74,304
Net operating loss carryforward		216,777
		295,655
Deferred income tax liabilities
Depreciation and amortization		(247,139	)
Regulatory and other reserves		(17,507	)
Other		(4,372	)
		(269,018	)
Net deferred income tax asset	$	26,637

Tax Provision

Total income tax expense (benefit) for the year ended December 31, 2003 is summarized as follows: (in thousands):

Payable currently
Federal	$	13,082
State		2,373
		15,455
Payment deferred
Federal		8,006
State		1,831
		9,837
Total income tax expense	$	25,292

The differences between taxes computed at the U.S. Federal statutory rate of 35 percent and Transwestern’s effective rate for 2003 are as follows (in thousands):

Statutory federal income tax	$	22,533
State income tax, net of federal benefit		2,733
Other		26
Total income tax expense	$	25,292

(3) Long-Term Debt

On November 6, 2003, Transwestern entered into a Consent and Fifth Amendment to Credit Agreement (of its November 13, 2001 $550.0 million revolving credit facility agreement (the 2001 Credit Agreement). The 2001 Credit Agreement was collateralized by all of the common stock of Transwestern and, subject to certain exceptions, all other assets of Transwestern. When the debt was initially incurred in 2001, $412.5 million of the proceeds under the Credit Agreement were loaned to Enron. In addition, Transwestern assumed an Enron obligation of $137.5 million, which was recorded as an additional advance to Enron. The interest rate in effect under the 2001 Credit Agreement at December 31, 2003 was 4.42 percent, based on LIBOR plus 3.25 percent. The estimated fair value of Transwestern's short-term debt at December 31, 2003 was $461.0 million.

The Consent and Sixth Amendment to the 2001 Credit Agreement was executed on March 31, 2004. The Sixth Amendment cured the default created under that agreement by Enron’s registration under PUHCA and amended it to reflect the transfer of the TW Holdings stock to CrossCountry (see Note 10).

As a condition precedent to the 2001 Credit Agreement, Enron completed a corporate restructuring of Transwestern designed to further separate Transwestern from Enron and its other affiliates. This restructuring involved formation of a new stock holding company, TW Holdings, and two voting trusts, TPC Voting Trust and THC Voting Trust (the Trusts), both with Wilmington Trust Co. (Wilmington) as the voting trustee. The Trusts allowed TW Holdings to retain ownership of Transwestern, while effectively giving Transwestern’s lenders a minority voting interest in Transwestern sufficient to block a voluntary bankruptcy. During 2001, Enron Transportation Services (ETS) contributed all of the stock of Transwestern to TW Holdings, in exchange for all of the stock of TW Holdings. ETS then contributed 20 percent of the stock of TW Holdings to THC Voting Trust, in exchange for all of the beneficial interests of THC Voting Trust. TW Holdings then contributed 20 percent of the stock of Transwestern to the TPC Voting Trust in exchange for all of the beneficial interests of that Trust. Both the shares of Transwestern and the beneficial interests of the Trusts were pledged to the lenders.

Transwestern classified its debt as current at December 31, 2003 because, at the time these financial statements were originally issued, there was substantial doubt about Transwestern’s ability to fund its operations from existing cash flows. On May 3, 2004, Transwestern arranged replacement financings for its short-term debt, which was scheduled to mature in November 2004 and, accordingly, provided sufficient cash flows for its operating activities. Transwestern obtained a $150.0 million four-year revolving credit facility and a $400.0 million five-year term loan facility, and used the proceeds to repay the existing indebtedness under the Credit Agreement and finance the ongoing working capital, capital expenditures, and other general corporate requirements of Transwestern. On May 24, 2004, Wilmington can celed both of the voting trusts and no longer has a voting interest in Transwestern, and CrossCountry owns 100 percent of TW Holdings and TW Holdings owns 100 percent of Transwestern.

Effective November 17, 2004, Transwestern entered into new credit agreements for (i) $270.0 million of ten-year senior unsecured notes bearing interest at a fixed rate of 5.39 percent, maturing November 17, 2014, $20.0 million of which will not be drawn down until March 15, 2005; (ii) $250.0 million of twelve-year senior unsecured notes bearing interest at a fixed rate of 5.54 percent, maturing November 17, 2016; and (iii) a $230.0 million credit agreement comprised of a $100.0 million five-year term loan bearing interest at LIBOR plus 75 basis points, maturing November 17, 2009 (the Term Loan) and a $130.0 million five-year revolving credit facility bearing interest at LIBOR plus 75 basis points, due on November 17, 2009 (collectively, the Refinancing). Proceeds from the Refinancing were used to retire the May 2004 debt and to pay distributions to its equity holder totaling $241.7 million (see Note 10). The costs of the Refinancing are amortized to interest expense ratably over the life of each debt instrument.

(4) Property, Plant and Equipment

The principal components of Transwestern’s Property, Plant and Equipment at December 31, 2003 are as follows (in thousands):

Transmission Plant	$	571,644
General Plant		30,403
Intangible Assets		26,036
Construction Work-in-progress		1,004
Acquisition adjustment		438,767
Property, Plant and Equipment, at Cost		1,067,854
Less - Accumulated depreciation and amortization		(138,759	)
Property, Plant and Equipment, Net	$	929,095

Included in gross property, plant and equipment is an aggregate plant acquisition adjustment of $438.8 million, which represents costs allocated to Transwestern’s transmission plant as a result of its acquisition by Enron in 1984. Currently, this amount is not considered by the FERC in determining tariff rates Transwestern may charge to its regulated customers. The unamortized balance of this adjustment is $282.2 million at December 31, 2003.

Intangible assets from above include the following (in thousands):

	2003			Weighted-average amortization period       (in years)
Intangible Assets:
Software licenses	$	15,757			10
Contribution in aid of construction		10,279			12
Intangible Assets, at Cost		26,036
Less - Accumulated depreciation and amortization		(12,323	)
Intangible Assets - Net	$	13,713

Amortization of intangible assets is estimated to be approximately $2.7 million in 2004, $2.4 million in 2005, $2.3 million in 2006, $2.0 million in 2007 and $1.6 million in 2008.

(5) Accounts Receivable and Related Activity

Transwestern has a concentration of customers in the electric and gas utility industries. This concentration of customers may impact Transwestern’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral to Transwestern. Transwestern sought additional assurances from customers due to credit concerns, and held aggregate prepayments of $3.9 million at the end of 2003. Transwestern’s management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minima l credit risk.

The following customers accounted for a significant portion of Transwestern’s total revenues during the year ended December 31, 2003 (in millions):

Southern California Gas Company (SoCal)	$	50.4
BP Energy Company (BP)		23.3
Pacific Gas and Electric Company (PGE)		17.8

Transwestern had receivables of $4.2 million from SoCal and $1.9 million from BP at December 31, 2003. Transwestern held a prepayment of $1.8 million from PGE at December 31, 2003, which is presented in the accompanying balance sheet as deferred revenue.

At December 31, 2003, Transwestern had fully reserved accounts receivable from bankrupt Enron affiliates (see Notes 9 and 10).

(6) Employee Benefit Plans

During 2003, the employees of Transwestern were covered under Enron’s benefit plans. During the year ended December 31, 2003, Transwestern was charged $6.2 million for all such benefits. Transwestern’s participation in the Enron benefit plans terminated during November 2004.

Enron maintained a pension plan that was a noncontributory defined benefit plan, the Enron Corp. Cash Balance Plan (the Cash Balance Plan) covering certain Enron employees in the United States and certain employees in foreign countries. The basic benefit accrual was 5 percent of eligible annual base pay. The cost of the Cash Balance Plan charged by Enron to Transwestern was $1.2 million during 2003.

Enron initiated steps to terminate the Cash Balance Plan in 2003.Effective January 1, 2003, Enron suspended the 5 percent benefit accruals under the Cash Balance Plan. Each employee’s benefit continued to accrue interest based on ten-year Treasury Bond yields. The Cash Balance Plan was underfunded at December 31, 2003. If such Plan were to terminate, other than in a standard termination, while underfunded, claims with respect to the underfunded benefit liability could be asserted, jointly and severally, against each member of th e Enron “controlled group of corporations” within the meaning of Section 414 of the Tax Code, and certain other Enron affiliates. In addition, Transwestern, as a former participating employer in certain Enron benefit plans, may have indemnity obligations in favor of committee members and others under certain Enron benefit plans that are the subject of litigation asserting, among other claims, breaches of fiduciary duty. On December 31, 2003, Enron filed a motion with the Bankruptcy Court seeking authorization to contribute up to $200.0 million to fund and terminate the Cash Balance Plan and other pension plans of related debtor companies and affiliates. The Bankruptcy Court approved the motion on January 29, 2004. On February 5, 2004, Enron’s Board of Directors voted to amend and terminate the Cash Balance Plan. The Cash Balance Plan’s official termination date was to be May 31, 2004. Before the Plan could be terminated, Enron was required to comply with certain federal regulatory require ments, including filing for necessary approvals and notifying Cash Balance Plan participants of the Plan termination at least 60 days prior to the termination date. Both the Pension Benefit Guaranty Corporation (PBGC) and the Internal Revenue Service (IRS) had to approve the termination of the Plan. In 2003, Transwestern recognized its estimated portion of the expected Cash Balance Plan settlement by recording a $3.2 million current liability, and a charge to operating and maintenance expenses. This liability was increased to $5.9 million in June 2004 as a result of the completion of a third party actuarial calculation. Also in June 2004, the PBGC filed a complaint in the United States District Court for the Southern District of Texas to terminate the Cash Balance Plan and other pension plans of Enron debtor companies and affiliates (the Plans). If the PBGC successfully terminated the Plans in this suit, each member of the Enron “controlled group of corporations” within the meaning of Section 414 o f the Tax Code, and certain other Enron affiliates, would be jointly and severally liable, under Title IV of ERISA, for the Plans’ unfunded benefit liabilities. Under certain circumstances, the PBGC may enforce ERISA Title IV liability through the imposition of liens. On September 10, 2004, Enron agreed to deposit $321.8 million in an escrow account to cover, among other things, the unfunded benefit liabilities relating to the Plans. The escrow account was funded with a portion of the proceeds from Enron’s sale of CrossCountry. Under the Purchase Agreement (see Note 10), Transwestern is not required to make further contributions to the Cash Balance Plan, beyond its accrued liability, after the date of the Purchase Agreement. Although there can be no assurance that Transwestern will not have further obligations with respect to the Plans or other Enron benefit plans, Transwestern does not believe that the ultimate resolution of these matters will have a material adverse effect on its financial positi on, results of operations or cash flows. Under the Purchase Agreement (see Note 10), Enron agreed (subject to a cap) to indemnify and hold harmless Transwestern, CrossCountry and certain other members of the CrossCountry group for, among other things, any joint and several liability arising under Title IV of ERISA or due to Transwestern’s status as a participating employer in certain Enron benefit plans, including the Cash Balance Plan.Transwestern’s net periodic post-employment benefit cost charged by Enron was $0.6 million in 2003.

Transwestern is a participating employer in the Enron Gas Pipelines Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to former employees of Transwestern and certain other Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp. Medical Plan for Inactive Participants. Enron has made the determination that it will partition the Trust and distribute the assets and liabilities of the Trust among the participating employers of the Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer. The Trust Committee has final approval on allocation methodology for the Trust assets. Enron filed a motion, which has been stayed, which provides th at each participating employer expressly assumes liability for its allocable portion of retiree benefits and releases Enron from any liability with respect to the Trust in order to receive the assets of the Trust.

(7) Rate Matters and Regulatory Issues

Rate matters and regulatory issues are regulated by the FERC, and are subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 allows companies whose service obligations and prices are regulated to record deferred charges (regulatory assets) representing costs they expect to recover from customers through inclusion in future rates. Likewise, costs recovered that should be excluded from the rate base are recorded as deferred credits (regulatory liabilities). If events were to occur that would make the recovery of these assets and liabilities no longer probable, Transwestern would be required to write down these regulatory assets and liabilities.

The principal components of Transwestern’s regulatory assets at December 31, 2003 are as follows (in thousands):

Current regulatory assets:
Annual cost adjustment	$	1,031
Accumulated reserve adjustment		601
AFUDC gross-up		103
Deferred contract reformation costs		1,668
Deferred loss on receivables		760
Litigation costs		867
Purchase gas adjustments alternative rate recovery		537
Other		1,125
	$	6,692
Noncurrent regulatory assets:
Accumulated reserve adjustment	$	44,393
AFUDC gross-up		6,971
Deferred contract reformation costs		1,907
Deferred loss on receivables		1,696
Litigation costs		1,287
Purchase gas adjustments alternative rate recovery		984
Other		5,075
	$	62,313

At December 31, 2003, substantially all of Transwestern’s regulatory assets are recoverable in rates.

The accumulated reserve adjustment included in the table above resulted from a settlement agreement dated May 2, 1995 (May 2, 1995 Settlement) further described below. The settlement approved Transwestern’s proposal to refunctionalize certain facilities from production and gathering to transmission, and from transmission to production and gathering. As directed by the FERC Order (Docket No. RP95-271-000) issued upon approval of the settlement, Transwestern established a regulatory asset for an accumulated reserve adjustment of $50.1 million, which represents the difference between recorded amounts of accumulated depreciation (determined on a vintage basis) and approved amounts of accumulated depreciation based on remaining reserves related to the gathering facilities. The accumulated reserve adjustment is being amortized at a 1.2 percent annual rate. Concurrent with the amortization, Transwestern records an entry to reduce depreciation expense and reduce accumulated amortization. Management believes that these entries are appropriate based on the intent of the settlement. Transwestern intends to continue to seek recovery of this asset in future rate case filings.

Transwestern is involved in several rate matters and regulatory issues, the significant items of which are discussed below.

Since 1988, Transwestern has filed approximately $278.7 million in transition costs (deferred contract reformation costs) with the FERC under FERC Order Nos. 500 and 528, providing for recovery from customers of approximately $215.5 million. Of total transition costs incurred, $3.6 million remains to be collected as of December 31, 2003 over the period ending October 31, 2006.

In the May 2, 1995 Settlement, Transwestern and certain of its current firm customers also agreed to contract settlement rates through the lives of these customers’ contracts, and agreed that Transwestern would not be required to file a new rate case to become effective prior to November 1, 2006. The settlement was approved on July 27, 1995.

On December 29, 2003, the Securities and Exchange Commission (SEC) denied Enron’s outstanding applications for exemption under the Public Utility Holding Company Act of 1935 (PUHCA). Enron applied for another exemption on December 31, 2003. Under PUHCA, Transwestern was a subsidiary company of a holding company, but was eligible for certain exemptions if such exemptions are applied for by Enron and approved by the SEC.

On February 6, 2004, Enron filed two form U1’s with the SEC, proposing a set of conditions under which Enron would register as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). On March 9, 2004, Enron amended its form U1 application filings, withdrew its application for exemption filed on December 31, 2003, and filed a form U5A, registering as a public utility holding company under PUHCA. Also on March 9, 2004, the SEC issued orders approving the applications made on the amended form U1’s and the U5A. At that time Transwestern became subject to PUHCA as a “subsidiary company” of a “registered utility holding company.” As of November 17, 2004, as a result of the sale of Transwestern by Enron to CCE Holdings, Transwestern is no longer a subsi diary of a registered utility holding company (see Note 10).

Transwestern filed on April 8, 2004 an application with the FERC for a proposed expansion project (Expansion Project) that will increase incremental capacity by 375,000 dekatherms per day on the San Juan Lateral from the Blanco Hub, located in San Juan County, New Mexico, to the Gallup area located at the interconnection of the San Juan Lateral and Transwestern’s mainline. The Expansion Project will expand Transwestern’s natural gas transmission system through the construction of approximately 72.6 miles of pipeline looping on the existing San Juan Lateral and causing Transwestern to abandon, install, and modify facilities at three existing compressor stations for additional compression totaling 20,000 horsepower. The Expansion Project was approved by the FERC in July 2004, and the facilities are expe cted to be in-service by mid-2005 at an estimated cost to construct of $145.7 million.

(8) Commitments and Contingencies

From time to time, in the normal course of business, Transwestern is involved in litigation, claims or assessments that may result in future economic detriment. Transwestern evaluates each of these matters and determines if loss accruals are necessary as required by SFAS No. 5, “Accounting for Contingencies.” Transwestern does not expect to experience losses that would be materially in excess of the amounts accrued at December 31, 2003.

Legal Proceedings

In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293 (D. Wy), previously Civil Action Nos. 97-D-1421 (D. Colo.) and 97-2087 (E.D. La.) and other consolidated cases. The plaintiff has filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. Transwestern believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which is filed with and approved by FERC. Transwestern’s legal exposure, if any, related to the ultimate resolution of this matter is not currently determinable.

Transwestern Pipeline Company v. Burlington Northern and Santa Fe Railway Company, et al (Case No. CV-2003-180 II, 11^th Judicial District Court, McKinley County, New Mexico). Transwestern filed suit against Burlington Northern (Burlington) on May 22, 2003 for damages incurred as a result of a Burlington train derailment on October 29, 2000 and subsequent repair activities. Transwestern filed an amended complaint to specifically include Burlington’s contractors. Burlington has joined Burlington’s contractors and the contractor’s insurers. Discovery is ongoing. This is an insured matter and therefore the claim is being pursued by and on behalf of Transwestern and Transwestern’s underwriters. Transwestern has received payment in the amount of $0.4 million from the underwriters for the insured portion of the claim. Transwestern is pursuing the deductible of $0.5 million, among other damages. The matter was settled in principle at mediation on January 28, 2005.

Transwestern is managing three threatened trespass actions related to right of way (ROW) on Tribal or allottee land. The first action involves an agreement with the United States Department of the Interior, Bureau of Indian Affairs (BIA) covering 44 miles of ROW on a total of 69 Navajo allotments. This ROW agreement expired on January 1, 2004. One allottee, Mr. Leon Gibson, sent a letter dated January 16, 2004 to the BIA claiming Transwestern is trespassing. Discussions are ongoing with the BIA to approve the renewal application, which was filed in October 2002. The second action involves a 1990 Grant of Easement and Right of Way by the Secretary of the Interior covering 6.6 miles of Southern Ute land assigned by Northwest Pipeline Corporation (Northwest Pipeline) to Transwestern in 1996. Application was made t o the BIA for approval of that assignment, but no action was taken. On May 27, 2003 and September 2, 2003, counsel for the Southern Ute Tribe sent letters to Transwestern alleging trespass. Under the operative regulations and the underlying agreements, Transwestern believes that the consent of the Tribe is not required to assign the ROW grant from Northwest Pipeline to Transwestern. The third action concerns 5,100 feet of ROW on private allotments within the Laguna Pueblo expired on December 28, 2002. Transwestern received a letter dated March 19, 2003 from the BIA on behalf of the two allottees asserting trespass. Transwestern’s legal exposure related to this matter is not currently determinable.

Rates and Regulatory Matters

In February 2001, Transwestern filed with FERC negotiated rate transactions with Sempra Energy Trading (Sempra) and Richardson Products Company (Richardson) containing index-based rates. The FERC subsequently issued an order that required Transwestern to refund the amounts by which the negotiated rate transactions with Sempra and Richardson exceeded Transwestern's applicable maximum tariff rates. In the order, the FERC stated that Transwestern violated the terms of its FERC Gas Tariff in entering into those transactions. Transwestern subsequently negotiated with its customers a settlement of all pending negotiated rate proceedings with the exception of the rate proceedings in connection with the Red Rock E xpansion Project. This settlement has been approved by FERC and Transwestern made the refunds of $9.9 million (including interest of $1.1 million), required by the settlement on March 14, 2003.

On August 1, 2002, the FERC issued an Order to Respond (August 1 Order) to Transwestern. The order required Transwestern, within 30 days of the date of the order, to provide written responses stating why the FERC should not find that: (i) Transwestern violated FERC's accounting regulations by failing to maintain written cash management agreements with Enron; and (ii) the secured loan transactions entered into by Transwestern in November 2001 were imprudently incurred and why the costs arising from such transactions should be passed on to ratepayers. Transwestern filed a response to the August 1 Order and subsequently entered into a settlement with the FERC staff that resolved, as to Transwestern, the issues raised by the August 1 Order. The FERC approved this settlement; however, a group of Transwestern’s customers filed a request for clarification and/or rehearing of the FERC order approving the settlement. This customer group claimed that there is an inconsistency between the language of the settlement agreement and the language of the FERC order approving the settlement. This alleged inconsistency relates to Transwestern’s ability to pass through to its ratepayers the costs of any replacement or refinancing of the secured loan transactions entered into by Transwestern in November 2001. Transwestern filed a response to the customer group’s request for rehearing and/or clarification and this matter is currently awaiting FERC action.

On December 15, 2003, the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (HCA). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002, a bill signed into law on December 17, 2002. The rule requires operators to identify HCAs along their pipelines by December 2004, and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing, or direct assessment, by June 2004. Operators must risk rank their pipeline segments containing HCAs, and have the highest 50 percent assessed using one or more of these methods by December 2007. The balance must be completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the inspections. Because identification and location of all the HCAs has not been completed, and because it is impossible to determine the scope of required remediation activities prior to completion of the assessments and inspections, the cost of implementing the requirements of this regulation is impossible to determine at this time. The required modifications and inspections are estimated to range from approximately $12.0 - $15.0 million per year, with remediation costs in addition to these amounts. A provision in the Settlement described above provides for recovery of some added assessment and repair/replacement capital costs via a special capital surcharge, if certain conditions are met.

Environmental Matters

Transwestern is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenses. These increased operating expenses are not expected to have a material impact on Transwestern’s financial position or results of operations.

Transwestern conducts soil and groundwater remediation at a number of its facilities. During 2003 these costs totaled $1.2 million. Using a discount rate of 5 percent, the net present value of the costs over the next five years is expected to be: 2004 - $2.0 million, 2005 - $1.5 million, 2006 - $0.3 million, 2007 - $0.2 million and 2008 - $0.2 million. The net present value of expenditures thereafter is estimated to be $0.7 million for soil and groundwater remediation. The net present value accrual is recognized in other current liabilities and other deferred credits and other liabilities, and the change in such value is charged to operating and maintenance expenses.

Transwestern incurred, and continues to incur, certain costs related to polychlorinated biphenyls (PCBs) that migrated into customer’s facilities. These PCBs were originally introduced into the Transwestern system through use of a PCB-based lubricant in the late 1960’s and early 1970’s. Because of the continued detection of PCBs in the customer’s facilities downstream of Transwestern’s Topock and Needles stations, Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities during 2003 totaled $1.2 million. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers, and accordingly, no accrual h as been established for these costs at December 31, 2003. However, such future costs are not expected to have a material impact on Transwestern’s financial position or results of operations or cash flows.

Capital Commitments and Purchase Obligations

The Department of Revenue of the State of Colorado (DOR) assessed Transwestern $0.6 million in sales and use taxes and $0.7 million in penalties and interest relating to the purchase by Transwestern of an undivided interest in certain pipeline facilities located in Colorado from Northwest Pipeline Corporation. In addition, the DOR assessed Transwestern additional amounts for taxes relating to the use of compressor fuel at facilities located in the State of Colorado. In March 2004, Transwestern and the DOR reached a settlement of this matter. Under the terms of the settlement, Transwestern (i) paid $0.7 million to the DOR to settle the assessment relating to the purchase of the undivided interest in the pipeline facilities; and, (ii) agreed to pay the compressor fuel tax on a prospective basis beginning with the month of February 2004. At December 2003, the accrual is recorded within other current liabilities and charged to taxes, other than income taxes.

One of Transwestern’s affiliates participated in the 1992 acquisition of a license to operate a natural gas pipeline in Argentina. Transwestern guaranteed certain limited performance obligations of that affiliate to certain joint venture partners of that affiliate and has agreed to provide technical support to that affiliate in connection with the operation of the pipeline. In addition, at the time of the acquisition, Transwestern was deemed to be part of the “economic group” of Enron-controlled companies and Transwestern’s net worth was used to satisfy certain net worth requirements established by the Argentine government relating to the acquisition of the license to operate such pipeline. Upon the closing of the Purchase Agreement (see Note 10) on November 17, 2004, Transwestern and certai n of its affiliates were indemnified and held harmless by Enron against third-party claims relating to Transwestern’s participation in this project, other than liabilities that result from any action or inaction by Transwestern that is not in accordance with certain performance standards agreed upon by Enron and Transwestern’s parent company. In addition, on April 16, 2004, the joint venture participants in the project granted Transwestern a release from any liability of Transwestern to such participants as a result of Transwestern being considered part of the Enron economic group. This release has been approved by the bankruptcy court.

Transwestern has operating leases, some of which are CPI adjusted, which extend existing rights-of-way along its natural gas pipeline system. Lease payments charged to expense were $0.9 million during 2003. Future minimum payments under non-cancelable leases are as follows (in millions):

Year Ending	Operating
December 31	Leases
2004	$	3.0
2005		3.2
2006		3.2
2007		3.2
2008		3.2
Thereafter		6.0
Total	$	21.8

Included in the above schedule is a six-year lease agreement that commenced January 1, 2004 and includes annual payments of $2.3 million. The remainder of lease expense pertains to a 20-year lease agreement with annual payment requirements of $0.3 million which became effective on December 28, 2002.

(9) Related Party Transactions

On December 2, 2001, Enron and certain of its subsidiaries filed voluntary petitions under Chapter 11 of the Bankruptcy Code. As a result, a $784.7 million note receivable from Enron was reserved due to the uncertainty regarding Enron’s ability to repay. In 2002, the value of the receivable was determined by Transwestern management to be substantially impaired. As a result, the receivable was completely written off against the reserve for book purposes and 80 percent ($628.5 million) was written off for tax purposes creating a $240.8 million NOL carry forward. Enron has utilized a portion of this NOL in its consolidated tax return.

At December 31, 2003, Transwestern had $34.1 million of receivables from bankrupt Enron affiliates that were fully reserved (see Note 10).

Transwestern has entered into compression services agreements with Enron Compression Services Company (ECS), an Enron affiliate that is not in bankruptcy. The agreements require Transwestern to pay ECS a compression service charge in cash and in-kind to provide electric horsepower capacity and related horsepower hours to be used to operate the Bisti, Bloomfield, and Gallup electric compressor stations located in New Mexico. ECS is required to pay Transwestern a monthly fee to operate and maintain the facilities. Transwestern and ECS entered into a Purchase and Settlement Agreement and Mutual Release dated April 30, 2004 (the Purchase and Settlement Agreement). The Purchase and Settlement Agreement (i) caused the sale of certain motor and drive systems of ECS to Transwestern; and (ii) amended and restated the ag reements between Transwestern and ECS. Effective December 1, 2004, ECS assigned all of its interest in the compression services agreements to Paragon ECS Holdings, LLC, a non-affiliated entity.

Related to Enron’s bankruptcy, the bankruptcy judge authorized an overhead expense allocation methodology on November 25, 2002. Transwestern’s final allocation for 2003 has not been determined at this time. In compliance with the authorization, recipient companies subject to regulation and rate base constraints may limit amounts remitted to Enron to an amount equivalent to 2001, plus quantifiable adjustments. Transwestern has invoked this regulation and rate base constraint limitation in the calculation of expenses accrued for 2003. Transwestern accrued administrative expenses from Enron and affiliated service companies of approximately $11.5 million during 2003. These costs are based on usage, or where no direct method is reasonable, Transwestern’s components of gross property, plant and equipme nt, gross margin and annualized payroll as a percentage of all Enron companies.

Effective November 17, 2004, Transwestern distributed as a dividend to its parent, its rights, title, interest and claims with respect to Enron and certain of its bankrupt subsidiaries, totaling approximately $824.6 million. This dividend had no effect on Transwestern’s financial statements as such rights, title, interest and claims had been written off in prior years. Also effective November 17, 2004, Transwestern refinanced its outstanding debt and paid distributions to its equity holder totaling $241.7 million (see Note 10).

(10) Subsequent Events

Effective March 31, 2004, the CrossCountry formation transaction closed, in which certain Enron equity interests in TW Holdings were transferred to CrossCountry in exchange for interests in CrossCountry. Transwestern is a wholly-owned subsidiary of TW Holdings, and TW Holdings is a wholly owned subsidiary of CrossCountry.

On May 3, 2004, Transwestern arranged replacement financings for its short-term debt, which was scheduled to mature in November 2004. Transwestern obtained a $150.0 million four-year revolving credit facility and a $400.0 million five-year term loan facility, with the proceeds used to repay the indebtedness under its 2001 Credit Agreement and finance the ongoing working capital, capital expenditures, and other general corporate purposes of Transwestern.

Effective November 17, 2004, CrossCountry was acquired by CCE Holdings, a joint venture owned by subsidiaries of Southern Union (50 percent), GE (30 percent) and four minority interest holders (20 percent in the aggregate). All of the voting interests are owned by Southern Union and GE. At or about the time of the acquisition, among other things:

·   Transwestern, along with certain other affiliated entities, was converted to a limited liability company (LLC).  As a single-member LLC, Transwestern is a disregarded entity for federal income tax purposes, and will be included in the Federal Partnership tax return of CCE Holdings; 

·   Transwestern refinanced its outstanding debt and paid distributions to its equity holder as described below;

·   Transwestern and Enron terminated the 2004 Tax Sharing Agreement and the 1994 Tax Allocation Agreement, with each party releasing the other from any further rights, obligations or liabilities (see Note 2).  In connection with this termination, Enron paid Transwestern $62.5 million, representing the net amount due for, among other things, the remaining tax receivable that arose under this agreement in prior years;

·   Transwestern’s rights, title and interest in its claims against Enron and certain of its bankrupt subsidiaries, totaling approximately $824.6 million, were transferred in the form of a dividend to its equity owners prior to the acquisition of CrossCountry by CCE Holdings;

·   Under a Guaranty Agreement with Enron and certain of its subsidiaries, CrossCountry and certain of its subsidiaries (including Transwestern) jointly and severally guaranteed all obligations of CCE Holdings related to the Purchase Agreement defined below.

The Consent and Sixth Amendment to the Credit Agreement was executed on March 31, 2004. The Sixth Amendment cured the default created by Enron’s registration under PUHCA and amended the Credit Agreement to reflect the transfer of the TW Holdings stock to CrossCountry.

Effective November 17, 2004, Transwestern entered into credit agreements for (i) $270.0 million of ten-year senior unsecured notes bearing interest at a fixed rate of 5.39 percent, maturing November 17, 2014, $20.0 million of which will not be drawn down until March 15, 2005; (ii) $250.0 million of twelve-year senior unsecured notes bearing interest at a fixed rate of 5.54 percent, maturing November 17, 2016; and (iii) a $230.0 million credit agreement comprised of a $100.0 million five-year term loan bearing interest at LIBOR plus 75 basis points, maturing November 17, 2009 (the Term Loan) and a $130.0 million five-year revolving credit facility bearing interest at LIBOR plus 75 basis points, due on November 17, 2009, (collectively, the Refinancing). Proceeds from the Refinancing were used by Transwestern to r etire the May 2004 debt and to pay distributions to its equity holder totaling $241.7 million. No principal payments are required under any of the new debt agreements prior to their respective maturity dates. The Term Loan is collateralized with substantially all of the assets and the capital stock of Transwestern.

In November 2004, the FERC issued an industry-wide Proposed Accounting Release that, if enacted as written, would require pipeline companies to expense rather than capitalize certain costs related to mandated pipeline integrity programs. The accounting release is proposed to be effective January 2005 following a period of public comment on the release. Transwestern already expenses such costs.

Effective December 16, 2004, Citicorp North America, Inc. (Citicorp) claimed, in its capacity as the Paying Agent and Co-Administrative Agent, that any recovery in the litigation captioned Enron Corp. et al. v. Citigroup, Inc. et al. (In re Enron Corp. et al.), adv. No. 03-93611 (AJG), ch. 11 no. 01-16034 (AJG) (Bankr. S.D.N.Y. filed Dec. 1, 2003) (the Litigation), together with legal fees and expenses incurred by Citicorp in defending the Litigation, would be indemnity obligations (the Obligations) of Transwestern under its Credit Agreement dated November 13, 2001. Under the terms of the Purchase Agreement, dated June 24, 2004 (as amended by that certain Amendment No. 1 to Purchase Agreement, dated September 1, 2004, and that certain Amendment No. 2 to Purchase Agreement, dated November 11, 2004), CCE Holdings and certain of its subsidiaries (including Transwestern) are indemnified against the Obligations by Enron and certain of its subsidiaries. Accordingly, the Company does not believe that it has any material liability from Citicorp’s claims.

EX-99.C

EXHIBIT 99.c

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Citrus Corp. and Subsidiaries:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of Citrus Corp. and Subsidiaries (the “Company”) at December 31, 2003, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require tha t we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        /s/ PricewaterhouseCoopers LLP

Houston, Texas

March 24, 2004

      EXHIBIT 99.c

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands)
	December 31,
	2003
ASSETS
Current Assets
Cash and cash equivalents	$	125,226
Accounts receivable - trade and other, net of allowance of $77		39,713
Price risk management assets		15,024
Materials and supplies		2,915
Other		4,294
Total Current Assets		187,172
Property, Plant and Equipment, at Cost
Completed plant		4,023,762
Construction work-in-progress		35,638
Property, Plant and Equipment, at Cost		4,059,400
Less - Accumulated depreciation and amortization		(1,072,072	)
Property, Plant and Equipment, net		2,987,328
Deferred Charges
Unamortized debt expense		9,051
Price risk management assets		58,492
Other		108,380
Total Deferred Charges		175,923
Total Assets	$	3,350,423

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands, Except Share Data)
	December 31,
	2003
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable
Trade and other	$	30,396
Affiliated companies		20,086
Accrued interest		19,054
Accrued Income taxes		1,148
Accrued taxes, other than income		10,349
Price risk management liabilities		25,136
Exchange gas imbalances, net		12,320
Current maturities of long-term debt		256,159
Other		283
Total Current Liabilities		374,931
Long-term Debt, net of current maturities		908,972
Deferred Credits and Other Liabilities
Deferred income taxes		676,341
Price risk management liabilities		80,446
Other		13,618
Total Deferred Credits and Other Liabilities		770,405
Commitments and Contingencies (Notes 9 and 13)		-
Stockholder’s Equity
Common stock ($1 par value; 1,000 shares authorized, issued and outstanding)		1
Additional paid-in capital		634,271
Accumulated other comprehensive income		(17,247	)
Retained earnings		679,090
Total Stockholders’ Equity		1,296,115
Total Liabilities and Stockholders’ Equity	$	3,350,423

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(In Thousands)
	Year Ended
	December 31,
	2003
Revenues
Gas sales	$	104,370
Gas transportation, net		442,010
Total Revenues		546,380
Costs and Expenses
Natural gas purchased		99,130
Operations and maintenance		117,086
Depreciation		44,462
Amortization		20,060
Taxes, other than income taxes		27,436
Total Costs and Expenses		308,174
Operating Income		238,206
Other Income (Expense)
Interest expense, net		(104,653	)
Allowance for funds used during construction		5,804
Other, net		(14,587	)
Total Other Income (Expense)		(113,436	)
Income Before Income Taxes		124,770
Income Taxes		48,554
Net Income	$	76,216

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In Thousands)
	December 31,
	2003
Common Stock
Balance, beginning and end of year	$	1
Additional Paid-in Capital
Balance, beginning and end of year		634,271
Accumulated Other Comprehensive Income (Loss):
Balance, beginning of year		(18,453	)
Recognition in earnings of previously deferred losses related to derivative instruments used as cash flow hedges		1,206
Balance, end of year		(17,247	)
Retained Earnings
Balance, beginning of year		602,874
Net income		76,216
Balance, end of year		679,090
Total Stockholders’ Equity	$	1,296,115

The accompanying notes are an integral part of these financial statements.

 

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands)
	Year Ended
	December 31,
	2003
Cash Flows From Operating Activities
Adjustments to reconcile Net Income to Net Cash Provided by Operating Activities:
Net income	$	76,216
Depreciation and amortization		64,522
Amortization of hedge loss in other comprehensive income		1,206
Amortization of premium and swap hedge loss in long-term debt		392
Amortization of regulatory assets and other deferred charges		12,000
Deferred income taxes		24,271
Price risk management fair market valuation revaluation		20,599
Price risk management assets and liabilities		7,150
Allowance for funds used during construction		(5,804	)
Other, net		16,401
Changes in operating assets and liabilities:
Accounts receivable, trade and other		9,443
Materials and supplies		422
Trade and other payables		(7,029	)
Accrued liabilities		3,746
Other current assets and liabilities		9,863
Cash Provided by Operating Activities		233,398
Cash Flows From Investing Activities
Additions to property, plant and equipment		(142,334	)
Allowance for funds used during construction		5,804
Retirements and dispositions of property, plant and equipment, net		(1,074	)
Cash Used in Investing Activities		(137,604	)
Cash Flows From Financing Activities
Repayment of long-term debt		(59,500	)
Principal payments on long-term debt		(25,750	)
Cash Used in Financing Activities		(85,250	)
Increase in Cash and Cash Equivalents		10,544
Cash and Cash Equivalents, Beginning of Year		114,682
Cash and Cash Equivalents, End of Year	$	125,226
Supplemental Disclosure of Cash Flow Information
Interest	$	105,641
Income taxes		19,488

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMNENTS

(1) Reporting Entity

Citrus Corp. (Citrus), a holding company formed in 1986, owns 100 percent of the stock of Florida Gas Transmission Company (Transmission), Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI), collectively the Company. At December 31, 2003, the stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a wholly owned subsidiary of Southern Natural Gas Company (Southern), as transferred by Southern in January 2004, and 50 percent by Enron Corp. (Enron). Southern’s 50 percent ownership had previously been contributed by its parent, El Paso Corporation (El Paso) in March 2003. Pursuant to Enron’s filed Plan of Reorganization, Enron has formed a new operating entity, CrossCountry Energy LLC (CrossCountry), and intends to contribute its interest in the Company to a new wholly-owned, direct subsidiary of CrossCountry, CrossCountry Citrus Corp. Although bankruptcy court approval for the contribution and separation has been received, certain approvals are still required. These approvals are expected to be completed in 2004.

Transmission, an interstate gas pipeline extending from South Texas to South Florida, is engaged in the interstate transmission of natural gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

Trading ceased all trading activities effective the fourth quarter of 1997, but continues to fulfill its obligations under the remaining gas purchase and gas sale contracts. Trading buys natural gas primarily from an affiliate of Southern, El Paso Merchant Energy and sells to Auburndale Power Partners, LP and Progress Energy Florida, Inc.

Trading is evaluating opportunities to sell or assign its remaining contracts.

CESI primarily provides transportation management and financial services to customers of Transmission. CESI terminated its O&M business due to increased insurance costs and pipeline integrity legislation that affects operators.

In October 2002, and May and July 2003, Transmission and Trading filed several claims and amendments of claims with the United States Bankruptcy Court for the Southern District of New York against Enron and other affiliated bankrupt companies, aggregating $220.6 million. Of these claims, Transmission has filed claims totaling $68.1 million and Trading totaling $152.5 million. Transmission and Trading claims against Enron North America Corp. (ENA) are $29.5 million and $152.3 million, respectively (see Note 13).

(2) Significant Accounting Policies

Regulatory Accounting

Transmission is subject to regulation by the FERC. Transmission’s accounting policies generally conform to Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Accordingly, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded under accounting principles generally accepted in the United States for non-regulated entities.

        Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and accounts have been eliminated in consolidation.

       Cash and Cash Equivalents

Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.

       Materials and Supplies

Materials and supplies are valued at the lower of cost or market value. Materials transferred out of warehouses are priced out at average cost.

       Revenue Recognition

Revenues consist primarily of gas transportation services. Reservation revenues on firm contracted capacity are recognized ratably over the contract period. For interruptible or volumetric based services, revenues are recorded upon the delivery of natural gas to the agreed upon delivery point. Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. Transmission is subject to FERC regulations and, as a result, revenues collected may be required to be refunded in a final order in the pending rate proceeding (see Note 9) or as a result of a rate settlement. Reserves are established for these potential refunds.

       Derivative Instruments

The Company engages in price risk management activities for both trading and non-trading activities and accounts for these under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (see Note 4). Instruments utilized in connection with trading activities are accounted for using the mark-to-market method and are reflected at fair value as Assets and Liabilities from Price Risk Management Activities in the Consolidated Balance Sheets. Earnings from revaluation of price risk management assets and liabilities are included in Other Income (Expense). Cash flow hedge accounting is utilized for non-trading purposes t o hedge the impact of interest rate fluctuations. Unrealized gains and losses from cash flow hedges are recognized according to SFAS No. 133 as other comprehensive income, and subsequently recognized in earnings in the same periods as the hedged forecasted transaction affects earnings. In instances where the hedge no longer qualifies as effective, hedge accounting is terminated prospectively and the accumulated gain or loss is recognized in earnings in the same periods during which the hedged forecasted transaction affects earnings. Where fair value hedge accounting is appropriate, the offset that is attributed to the risk being hedged is recorded as an adjustment to the hedged item.

Property, Plant and Equipment

Property, Plant and Equipment (See Note 10) consists primarily of natural gas pipeline and related facilities. The Company amortizes that portion of its investment in Transmission and other subsidiaries which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual composite rate of 1.6 percent based upon the estimated remaining useful life of the pipeline system. Transmission has provided for depreciation of assets net of estimated salvage value, on a straight-line basis, at an annual composite rate of 1.66 percent for 2003. The overall remaining useful life for Transmission’s assets at December 31, 2003 is 41 years.

Property, Plant and Equipment is recorded at its original cost. Transmission capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component (see following paragraph). Costs of replacements and renewals of units of property are capitalized. The original costs of units of property retired are charged to the depreciation reserves, net of salvage and removal costs. Transmission charges to maintenance expense the costs of repairs and renewal of items determined to be less than units of property.

The allowance for funds used during construction consists, in general, of the net cost of borrowed funds used for construction purposes and a reasonable rate on other funds when so used (the AFUDC rate). The allowance is determined by applying the AFUDC rate to the amount of construction work-in-progress. Capitalization begins at the time the Company begins the continuous accumulation of costs in a construction work order on a planned progressive basis and ends when the facilities are placed in service.

The Company applies the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” to account for asset impairments. Under this standard, an asset is evaluated for impairment when events or circumstances indicate that a long-lived asset’s carrying value may not be recovered. These events include market declines, changes in the manner in which an asset was intended to be used, decisions to sell an asset, and adverse changes in the legal or business environment such as adverse actions by regulators.

       Compressor Overhaul Expenses

In 2003, Transmission changed its method of accounting for compressor overhaul costs by adopting a method for current expense recognition of compressor overhaul costs. This change was the result of Management’s determination that such costs previously deferred would not be recovered through future tariff rates. In prior years, such costs were deferred and amortized ratably over the expected service life of the applicable overhaul item. A remaining unamortized balance of $7.0 million applicable to the previous method was expensed in 2003. An additional amount of $6.5 million related to 2003 overhaul costs, which would have been deferred under the previous methodology, was also expensed.

       Income Taxes

The Company accounts for income taxes (See Note 5) under the provisions of SFAS No. 109, "Accounting for Income Taxes".  SFAS No. 109 provides for an asset and liability approach to accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.

      Trade Receivables

The Company establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables. The Company considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility. Unrecovered trade accounts receivable charged against the allowance for doubtful accounts were $0.3 million in 2003.

       Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(3) Long-Term Debt and Other Financing Arrangements

Long-term debt outstanding at December 31, 2003 was as follows (in thousands):

Citrus
8.490% Notes due 2007-2009	$	90,000
Transmission
9.750% Notes due 1999-2008		32,500
8.630% Notes due 2004		250,000
10.110% Notes due 2009-2013		70,000
9.190% Notes due 2005-2024		150,000
7.625% Notes due 2010		325,000
7.000% Notes due 2012		250,000
Unamortized Debt Premium and Swap Loss		(2,369	)
		1,075,131
Total Outstanding		1,165,131
Long-Term Debt Due Within One Year		(256,500	)
Unamortized Debt Premium and Swap Loss Within One Year		341
	$	908,972

Annual maturities and sinking fund requirements on long-term debt outstanding as of December 31, 2003 were as follows (in thousands):

Year	Principal Amount	Amortization	(1)	Total
2004	$256,500	$(341)		$256,159
2005	14,000	(341)		13,659
2006	14,000	(341)		13,659
2007	44,000	(341)		43,659
2008	44,000	(341)		43,659
Thereafter	795,000	(664)		794,336
	$ 1,167,500	$ (2,369)		$ 1,165,131

(1) Amortization of the debt premium and swap loss recognized on financing arrangements.

Transmission’s 8.63 percent Notes are due to be repaid in November 2004 in the amount of $250.0 million. Also in 2004, Transmission has due an additional $6.5 million under its 9.75 percent Notes. Management intends to fund this $256.5 million in current maturities through the utilization of current working capital, future operating cash flows and incurrence of additional indebtedness. The portion of current obligations due which are not repaid through current working capital and future operating cash flows will be refinanced under new borrowing agreements or the restoration of Transmission’s ability to borrow on its $70.0 million revolving credit facility (see below). Transmission may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Transmission and the Company’s consolidated debt does not exceed specific debt to total capitalization ratios, as defined. Incurrence of additional indebtedness to refinance the current maturities would not result in a debt to capitalization ratio exceeding these limits.

Citrus has note agreements that contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets, the payment of dividends, and maintaining certain restrictive financial covenants. The agreements relating to Transmission's promissory notes include, among other things, restrictions as to the payment of dividends and maintaining certain restrictive financial covenants. As of December 31, 2003, the Company was in compliance with both affirmative and restrictive covenants of the note agreements.  

All of thedebt obligations of Citrus and Transmission have events of default which contain commonly used cross-default provisions.An event of default by either Citrus or Transmission on any of their borrowed money obligations, in excess of certain thresholds, which is not cured within defined grace periods, would cause the other debt obligations of Trans mission and Citrus to be accelerated. As discussed below, Transmission has obtained a waiver on its revolving credit facility; however, there are no outstanding borrowings under this facility which could cause an event of cross-default.

Transmission has a committed revolving credit agreement of $70.0 million (the Revolver), of which none was outstanding at December 31, 2003. Citrus absolutely and unconditionally guaranteed the obligations of Transmission under the line of credit agreement. On October 28, 2002, Transmission sought and obtained a 60-day waiver (the Waiver) of the requirement of Trading to hedge any open gas contracts within 45 days of knowledge of such open contracts (see Note 4). The Waiver has been renewed periodically since it was initially granted. Under th e Waiver, Transmission is prohibited from drawing under the facility, but is permitted to issue letters of credit, provided they are cash collateralized (see Note 17).

Transmission has an aggregate of $0.6 million in letters of credit under the revolving credit agreement. Per the terms of the Waiver, these issued and outstanding letters of credit are collateralized with cash.

Transmission sold $250.0 million of 144A bonds without registration rights in July 2002. These notes pay interest of 7 percent biannually on August 1 and February 1 of each year. The entire principal amount is due July 17, 2012.

In October 2003, Citrus paid the remaining principal of $78.8 million on the 11.10 percent Note due in 2006 and incurred a $0.7 million pre-payment expense.

(4) Derivative Instruments

The Company determined that its gas purchase contracts for resale and related gas sales contracts are derivative instruments and records these at fair value as price risk management assets and liabilities under SFAS No. 133, as amended. The valuation is calculated using a discount rate adjusted for the Company’s borrowing premium of 250 basis points, which creates an implied reserve for credit and other related risks. The Company estimated the fair value of all derivative instruments based on quoted market prices, current market conditions, estimates obtained from third-party brokers or dealers, or amounts derived using internal valuation models. In 2003 the Company changed its method of presenting price risk management assets and liabilities to reflect the fair market value of specific contracts. This cha nge had no impact on the Company’s reported income or cash flows. In prior years, the Company presented price risk management assets and liabilities at the net present value of the expected future cash flows associated with the respective sales or purchase contracts. At December 31, 2003, under the specific contracts presentation, the fair value for the price risk management assets and liabilities was $73.5 million and $105.6 million, respectively. The Company performs a quarterly revaluation on the carrying balances, based on management’s best estimate of the value of the underlying contracts, that is reflected in current earnings. The impact to earnings from revaluation, mostly due to price fluctuations and contract status, was a loss of $20.6 million for 2003.

ENA ceased performing under its purchase and sales contracts with Trading in December 2001. Subsequent to such date, Trading assumed responsibility for performance under the respective contracts and continued to transact business under the terms of these contracts throughout 2003 and 2002. As a result of the foregoing, Trading has reported revenues and expenses under such contracts on a gross basis for the year ended December 31, 2003, due to Trading becoming the primary obligor under such contracts.

Prior to the Enron bankruptcy, a principal counterparty to Trading’s gas purchase and sale agreements (as well as swaps) was ENA. ENA has rejected these contracts in bankruptcy. A pre-petition gas purchase payable to ENA of $12.4 million was reversed in 2003 when it was determined that the Company had a right of offset against claims for pre-petition receivables. Pursuant to an existing operating agreement (rejected by ENA in 2003 but under which an El Paso affiliate is still performing), an affiliate of El Paso was required to buy gas, purchased from a significant third party, that exceeded the requirements of existing sales contracts. Under this third party contract, gas was purchased primarily at rates based upon a formula. This gas was then sold primarily at market rates. On April 16, 2003, the signifi cant third party supplier terminated the supply contract. Trading currently only purchases the requirements to fulfill existing sales contracts from third parties at market rates. As a result of these developments, the cash flow stream is now dependent on variable pricing, whereas before Enron’s bankruptcy, the cash flow stream was fixed. The quarterly valuations are based on Management’s best estimate of the fair value of the underlying contracts. Changes in the future pricing projections could lead to material differences in the valuation of the derivative instruments.

Due to a dispute (see Note 13) during 2003, Duke Energy LNG Sales, Inc. (Duke) discontinued performance under a natural gas purchase and supply contract between it and Trading and subsequently purported to terminate the contract. As a result of this contract termination, during 2003, Trading discontinued the application of fair market value accounting for this contract, and wrote off the value of the related price risk management assets as a charge to Other Income (Expense) in the accompanying statement of operations. Pursuant to the terms of the contract and also during 2003, Trading issued to Duke, the counterparty, a termination invoice for approximately $187.0 million. As a result of the ongoing litigation regarding this matter, the termination invoice amount was recognized, net of appropriate reserves and certain related matters, including bankruptcy claims held by Trading against ENA, as an offsetting gain to Other Income (Expense), net and is presented as a net long term receivable of $72.5 million in Other Deferred Charges (see Note 11).

During 2001, Transmission entered into an interest rate swap transaction to hedge the fair value risk associated with $135.0 million of its existing long-term fixed rate debt. This transaction qualified and was accounted for as a fair value hedge in accordance with SFAS No. 133. Fair value recognition of this hedging instrument resulted in $3.2 million being recorded to price risk management liabilities and as an offset to long-term debt at December 31, 2001. This instrument was terminated in May 2002 with a fair value loss of $2.6 million being recorded in long term debt, which is being amortized over the life of th e debt issued as an adjustment to interest expense.

During 2002 Transmission initiated a new swap to hedge interest rate changes, which could occur between the initiation date of the swap and the issuance date of the July 2002 $250.0 million note offering. The aggregate notional amount of this swap was $250.0 million. This swap was terminated effective July 18, 2002. The $12.3 million fair value loss at the termination of the swap agreement was recognized as other comprehensive loss and is being amortized over the life of the related debt issue as an adjustment to interest expense.

(5) Income Taxes

The principal components of the Company's net deferred income tax liabilities at December 31, 2003 are as follows (in thousands):

Deferred income tax assets Alternative minimum tax credit Regulatory and other reserves Other	$	9,003 4,593 137
		13,733
Deferred income tax liabilities
Depreciation and amortization		658,501
Price risk management activities		16,565
Regulatory costs		11,052
Other		3,956
		690,074
Net deferred income tax liabilities	$	676,341

Total income tax expense for the year ended December 31, 2003 is summarized as follows (in thousands):

Current Tax Provision
Federal	$	19,215
State		5,068
		24,283
Deferred Tax Provision
Federal		21,930
State		2,341
		24,271
Total income tax expense	$	48,554

The differences between taxes computed at the U.S. federal statutory rate of 35 percent and the Company's effective tax rate for the year ended December 31, 2003 are as follows (in thousands):

Statutory federal income tax provision	$	43,670
State income taxes, net of federal benefit		4,816
Other		68
Income tax expense	$	48,554
Effective Tax Rate		38.9	%

The Company has an alternative minimum tax (AMT) credit which can be used to offset regular income taxes payable in future years. The AMT credit has an indefinite carry-forward period. For financial statement purposes, the Company has recognized the benefit of the AMT credit carry-forward as a reduction of deferred tax liabilities.

The Company files a consolidated federal income tax return separate from its parents.

(6) Employee Benefit Plans

The employees of the Company are covered under Enron’s employee benefit plans.Enron maintains the Enron Corp. Cash Balance Plan (“Plan”), which is a noncontributory defined benefit pension plan to provide retirement income for employees of Enron and its subsidiaries. Through December 31, 1994, participants in the Enron Corp. Retirement Plan with five years or more of service were entitled to retirement benefits in the form of an annuity based on a formula that used a percentage of final average pay and years of service. In 1995, Enron’s Board of Directors adopted an amendment to and restatem ent of the Retirement Plan, changing the plan’s name from the Enron Corp. Retirement Plan to the Enron Corp. Cash Balance Plan. In connection with a change to the retirement benefit formula, all employees became fully vested in retirement benefits earned through December 31, 1994. The formula in place prior to January 1, 1995 was suspended and replaced with a benefit accrual in the form of a cash balance of 5 percent of eligible annual base pay beginning in January 1, 1996. Pension expenses charged to the Company by Enron were $1.9 million for the year ended December 31, 2003.

Enron initiated steps to terminate the Cash Balance Plan in 2003. Effective January 1, 2003, Enron suspended the 5 percent benefit accruals under the Cash Balance Plan. Each employee’s accrued benefit will continue to be credited with interest based on ten-year Treasury Bond yields. Because the Company is not part of an Enron “controlled group”, as provided by Section 414(b) and (c) of the Internal Revenue Code of 1986, as amended, if the Plan were to be terminated or if the Company were to withdraw from participation in the Plan, the Company would be liable for only its proportionate share of any under-funding that may exist in the Plan at the time of such termination or withdrawal. On December 31, 2003, E nron Corp filed a motion with the Bankruptcy Court seeking authorization to contribute up to $200.0 million to fully fund and terminate the Cash Balance Plan and other pension plans of related debtor companies and affiliates. The Bankruptcy Court approved the motion on January 29, 2004. On February 5, 2004, Enron’s Board of Directors voted to amend and terminate the Enron Corp. Cash Balance Plan. The Cash Balance Plan’s official termination date is currently set for May 31, 2004. Before the Plan can be terminated, Enron must comply with certain federal regulatory requirements, including filing for necessary approvals and notifying Cash Balance Plan participants of the Plan termination at least 60 days prior to the termination date. Both the Pension Benefit Guaranty Corporation (“PBGC”) and the Internal Revenue Service (“IRS”) must approve the termination of the Plan (the IRS needs to determine that the Plan is tax-qualified as of the date of termination). In 2003, the Company re cognized its portion of the expected Cash Balance Plan settlement by recording a $9.6 million current liability and a charge to operating expense. The Company will seek to recover this expense from its customers through the pending rate case proceeding. Several creditors, including the PBGC, have filed objections to Enron’s Chapter 11 Plan. The PBGC is arguing that $200.0 million may be insufficient to fund the plans filed for termination in Enron’s December 31, 2003, motion with the Bankruptcy Court. The Bankruptcy Court has scheduled a hearing for April 20, 2004, on the Chapter 11 Plan. Based on the current status of the Cash Balance Plan settlement and the amount expected to be allocated to the Company as its proportionate share of the plan’s termination liability, the Company believes this accrual is adequate but not excessive. Although there can be no assurance that amounts ultimately allocated to and paid by the Company will not be materially different, we do not believe that the ultimat e resolution of this matter will have a materially adverse effect on the Company’s consolidated financial position or cash flows, but it could have significant impact on the results of operations in future periods.

Enron provides certain post-retirement medical, life insurance and dental benefits to eligible employees and their eligible dependents. The net periodic post-retirement benefit cost charged to the Company by Enron was $1.2 million for 2003. Substantially all of this amount relates to Transmission and is being recovered through rates.

Certain retirees of Transmission were covered under a deferred compensation plan managed and funded by Enron subsidiaries, one previously sold and the other now in bankruptcy. This matter has been included as part of the claim filed by Transmission in bankruptcy against Enron and other affiliated bankrupt companies. Transmission has not conceded that it has a legal responsibility to fund the obligations to these certain retirees, but has approved certain payments in the past in order to avoid litigation. If such obligation were deemed to be a liability to Transmission, the range of exposure is $0 to approximately $2.0 million. Transmission does not believe that the ultimate resolution of this matter will have a materially adverse effect on operating results, financial position or cash flow.

(7) Major Customers

Revenues from individual third party customers exceeding 10 percent of total revenues for the year ended December 31, 2003 were approximately as listed below (in millions):

Customers
Florida Power & Light Company	$	186.6

At December 31, 2003, the Company had receivables of approximately $15.1 million from Florida Power & Light Company.

(8) Related Party Transactions

In December 2001, Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy court. The Company was not included in the bankruptcy filing, and management believes that the Company will continue to be able to meet its own operational and administrative service obligations.

The Company incurs certain corporate administrative expenses from Enron and its affiliates. These services include administrative, legal, compliance, and pipeline operations emergency services.The arrangement was historically governed by the provisions of an operating agreement between an Enron affiliate and the Company which expired on June 30, 2001, and which has not been extended. However, Enron subsidiaries have continued to provide services under the terms of the original operating agreement. The Company reimburses the Enron subsidiaries for costs attributable to the operations of the Company. The Company expensed approximately $13.0 million for these charges for the year ended December 31, 2003.

Services provided by bankrupt Enron affiliates are allocated to the Company pursuant to a Bankruptcy Court ordered allocation methodology. Under that methodology, the Company is obligated to pay allocated amounts, subject to certain terms and conditions. Consistent with these terms and conditions, the Company accrues and pays the full amount for services it receives directly from the bankrupt Enron affiliates. Indirect Enron service allocations are capped commensurate with 2001 levels. In 2003, the Company accrued $2.1 million for indirect services and $9.4 million for direct services, and has paid a total of $10.1 million, of which $7.5 million was paid as of December 31, 2003. Final 2003 allocations will not be completed until mid-2004; however, the Company believes its 2003 accruals reflect reasonable estima tes for services received.

The Company provides natural gas sales and transportation services to El Paso affiliates at rates equal to rates charged to non-affiliated customers in the same class of service. Revenues related to these transportation services were approximately $5.3 million from El Paso affiliates for the year ended December 31, 2003. The Company’s gas sales were approximately $9.2 million to El Paso affiliates for the year ended December 31, 2003. The Company also purchased gas from affiliates of Enron of approximately $3.7 million and from affiliates of El Paso of approximately $26.9 million for the year ended December 31, 2003. Transmission also purchased transportation services from Southern in connection with its Phase III Ex pansion completed in early 1995. Transmission contracted for firm capacity of 100,000 Mcf/day on Southern’s system for a primary term of 10 years, to be continued for successive terms of one year each year thereafter unless cancelled by either party, by giving 180 days notice to the other party prior to the end of the primary term or any yearly extensions thereof. The amount expensed for these services totaled $6.6 million for the year ended December 31, 2003.

Effective the fourth quarter of 1997, the operation of the contracts held by Trading were divided between affiliates of Enron and El Paso. The fee charged, for services such as scheduling, billing, and other back office support, is based on a volumetric payment of $.005/MMBtu, or approximately 50 percent of the prior arrangement.During 2003, Trading accrued and paid $0.015 million to El Paso Merchant Energy and accrued $0.079 million and paid $0.243 million (for all post-petition items) to ENA, for administrative fees. Under this agreement, Trading was guaranteed an earnings stream based on all firm long-term c ontracts in place at November 1, 1997. The earnings stream now fluctuates due to the variable pricing currently in effect, the result of ENA rejecting all aspects of certain agreements in bankruptcy proceedings. As of September 8, 2003, Trading assumed operating responsibility relating to the securing of all supply not provided by El Paso Merchant Energy and scheduling of volumes (see Note 4).

The Company either jointly owns or licenses with other Enron affiliates certain computer and telecommunications equipment and software that is critical to the conduct of its business. In other cases, such equipment or software is wholly-owned by such affiliates, and the Company has no ownership interest or license in or to such equipment or software. Transmission participated in business applications that are shared among the Enron pipelines. All participating pipelines use the same common base system and also have a custom pipeline-specific component. Each pipeline pays for its custom development component and shares in the common base system development costs. There are specific software licenses that were entered into by an Enron affiliate that entitle Transmission to usage of the software licenses. Fees for this arrangement are included in the amounts paid for corporate administrative expenses.

Transmission is a party to a Participation Agreement, dated effective as of November 1, 2002, with Enron and Enron Net Works to provide Electronic Data Interchange (EDI) services through an outsourcing arrangement with EC Outlook. Enron renegotiated an existing agreement with EC Outlook that lowered the cost of EDI services and that also provided the means for Transmission to be compliant with the most recent North American Energy Standards Board (NAESB) EDI standards. The contract has a termination date of November 30, 2005. Fees for this arrangement are included in the amounts paid for corporate administrative expenses.

Transmission has a construction reimbursement agreement with ENA under which amounts owed to Transmission are delinquent. These obligations (including post-petition interest which cannot be collected) total approximately $7.4 million and are included in Transmission’s filed bankruptcy claims. These receivables were fully reserved by Transmission prior to 2003. Transmission has also filed proofs of claims regarding other claims against ENA in the bankruptcy proceeding (see Note 13). In its rate case filed with the FERC (see Note 9), Transmission has proposed to recover the estimated under-recovery on this obligation by rolling in the costs of the facilities constructed, less the estimated recovery from ENA, into its rates. However, Transmission cannot predict the amounts, if any, that it will collect or the timing of collection.

In addition to the above Transmission claim against ENA, Trading has filed proofs of claims against ENA totaling $152.3 million for commodity and financial transactions operable prior to ENA’s bankruptcy. Recovery of certain of these claimed amounts is interrelated with Trading’s gas purchase counterparty litigation and associated Other Deferred Charge (see Notes 4 and 13).

Transmission entered into a 20-year compression service agreement with Enron Compression Services Company (ECS) that commenced in April 2002. This agreement requires Transmission to pay ECS to provide electric horsepower capacity and related horsepower hours to be used to operate Compressor Station No. 13A, which consists of an electric compressor unit. Amounts paid to ECS in 2003 totaled $2.3 million. Under related agreements, ECS is required to pay Transmission an annual lease fee and a monthly operating and maintenance fee to operate and maintain the facilities. Amounts received from ECS in 2003 for these services were $0.4 million. A Netting Agreement, dated effective November 1, 2002, was executed with ECS, providing for the netting of payments due under each of the O&M, lease, and compression service agreements with ECS.

(9) Regulatory Matters

Transmission’s currently effective rates were established pursuant to a Stipulation and Agreement (Rate Case Settlement) which resolved all issues in Transmission’s Natural Gas Act (NGA) Section 4 rate filing in FERC Docket No. RP96-366. The Rate Case Settlement, approved by FERC Order issued September 24, 1997, provided that Transmission could not file a general rate case to increase its base tariff rates prior to October 1, 2000 (except in certain limited circumstances), and was required to file no later than October 1, 2001 (since extended to October 1, 2003 pursuant to the Phase IV settlement discussed below). The Rate Case Settlement also provided that the rates charged pursuant to Transmission’s Firm Transportation Service (FTS) rate schedule FTS-2 would decrease effective March 1, 1999 and March 1, 2000.

On October 1, 2003, Transmission filed a general rate case, proposing rate increases for all services, based upon a cost of service of approximately $165.0 million for the pre-expansion system and approximately $342.0 million for the incremental system. Based on Test Period reservation and usage determinants, the proposed rate increase under all Rate Schedules, ignoring the impact of existing rate caps, negotiated rates, and discounts, would generate approximately $56.0 million in additional annual transportation revenues for Transmission. The overall return requested is 11.81 percent, reflecting an 8.64 percent cost of debt and a 14.50 percent return on common equity, and is based on a capital structure of 45.92 percent debt and 54.08 percent equity. The cost of service for the pre-expansion system includes an increase in the depreciation rate applicable to onshore facilities, from 2.13 percent to 3.00 percent. In addition, Transmission has proposed certain revisions to various rate schedules. Other prospective changes proposed include the change to a traditional cost-of-service rate design (with straight-line depreciation, as opposed to variable depreciation under the currently-effective levelized rates) for the expansion system, a tracker for certain types of significant capital costs, and compliance with Order No. 637. A number of parties protested the rates. By order dated October 31, 2003, FERC suspended the proposed rates for five months (until April 1, 2004); set the tariff revisions limiting rights to convert FTS-1 service to Small Firm Transportation Service (SFTS), and setting a minimum volume for No Notice Transportation Service (NNTS) for a technical conference; set all other issues for hearing; accepted the tariff change with regard to limiting reservation charge credits but only in cases of force ma jeure events (thus, in force majeure events, Transmission would only be required to refund to customers the return and related income tax components of its rates). Transmission made the required compliance filing and several customers protested, to which Transmission filed an answer in opposition. FERC staff has issued its initial position on a number of issues. At a technical conference held on January 7, 2004, Transmission agreed to withdraw its NNTS minimum volume proposal, subject to certain customers withdrawing their nominations. An initial settlement conference was held on March 11, 2004; the next settlement conference is set for March 30. In the event a settlement is not achieved, the hearing is set for August 31, 2004.

On December 1, 1998, Transmission filed an NGA Section 7 certificate application with the FERC in Docket No. CP99-94-000 to construct 205 miles of pipeline in order to extend the pipeline to Ft. Myers, Florida and to expand capacity by 272,000 MMBtu/day (Phase IV Expansion). Expansion costs were estimated at $351.0 million. Transmission requested that expansion costs be rolled into the rates applicable to FTS-2 (Incremental) service. On June 2, 1999, Transmission filed a Stipulation and Agreement (Phase IV Settlement) which resolved all non-environmental issues raised in the certificate proceeding and modified the Rate Case Settlement to provide that Transmission cannot file a general rate case to increase its base tariff rates prior to October 1, 2001 (except in certain limited circumstances), and must file no later than October 1, 2003. The Phase IV Settlement was approved by the FERC by order issued July 30, 1999, and became effective thirty days after the date that Transmission accepted an order issued by the FERC approving the Phase IV Expansion project. On August 23, 1999, Transmission amended its application on file with the FERC to eliminate a portion of the proposed facilities (that would be delayed until the Phase V Expansion). The amended application reflected the construction of 139.5 miles of pipeline and an expansion of capacity in order to provide incremental firm service of 196,405 MMBtu on an average annual day, with estimated project costs of $262.0 million. The Phase IV Expansion was approved by FERC order issued February 28, 2000, and accepted by Transmission on March 29, 2000. The Phase IV Expansion was placed in service on April 30, 2001. Total costs through December 31, 2003, were $246.0 million.

On December 1, 1999, Transmission filed an NGA Section 7 certificate application with the FERC in Docket No. CP00-40-000 to construct 215 miles of pipeline and 90,000 horsepower of compression and to acquire an undivided interest in the existing Mobile Bay Lateral owned by Koch Gateway Pipeline Company (now Gulf South Pipeline Company, LP), in order to expand the system capacity to provide incremental firm service to several new and existing customers of 270,000 MMBtu on an average annual day (Phase V Expansion). Expansion and acquisition costs were estimated at $437.0 million. Transmission requested that expansion costs be rolled into the rates applicable to FTS-2 (Incremental) service. On August 1, 2000, and September 29, 2000, Transmission amended its application on file with the FERC to reflect the withdraw al of two customers, the addition of a new customer and to modify the facilities to be constructed. The amended application reflected the construction of 167 miles of pipeline and 133,000 horsepower of compression to create additional capacity to provide 306,000 MMBtu of incremental firm service on an average annual day. The estimated cost of the revised project is $462.0 million. The Phase V Expansion was approved by FERC Order issued July 27, 2001, and accepted by Transmission on August 7, 2001. Segments of the Phase V Expansion project were placed in service in December 2001, March 2002, and April 2003. Total costs through December 31, 2003 were $417.0 million.

On November 15, 2001, Transmission filed an NGA Section 7 certificate application with the FERC in Docket No. CP02-27-000 to construct 33 miles of pipeline and 18,600 horsepower of compression in order to expand the system to provide incremental firm service to several new and existing customers of 85,000 MMBtu on an average day (Phase VI Expansion). Expansion costs were estimated at $105.0 million. Transmission requested the expansion costs be rolled into rates applicable to FTS-2 (Incremental) service. The application was approved by FERC Order issued on June 13, 2002, and accepted by Transmission on July 19, 2002. Clarification was granted and a rehearing request of a landowner was denied by FERC Order of September 3, 2002. The Phase VI Expansion was completed and placed in service during 2003 with the excep tion of the compressor station modifications at stations 12, 15, and 24. Compressor station modifications at stations 12 and 24 were completed and placed in-service on January 31, 2004, and February 1, 2004, respectively. Modifications at compressor station 15 are scheduled to be completed by April 15, 2004. Total costs through December 31, 2003 were $73.0 million.

In July 2002, the FERC issued a Notice of Inquiry (NOI) that seeks comments regarding its 1996 policy of permitting pipelines to enter into negotiated rate transactions. On July 25, 2003, the FERC issued its “Modification of Negotiated Rate Policy”, in which it determined that it “will no longer permit the use of gas basis differentials to price negotiated rate transactions.” On August 25, 2003, the Interstate Natural Gas Association of America (INGAA) filed a request for rehearing of this ruling. On September 12, 2003, the Commission issued an order granting rehearing for the purposes of further consideration, thus, tolling the statutory time in which the FERC is required to act. On December 18, 2003, the Commission issued orders in two cases, essentially reversing this ruling for rates tha t will remain between the minimum and maximum tariff rates. Transmission has only two negotiated rate agreements, and both of these are at or below Transmission’s currently effective maximum tariff rates as well as the proposed rates in the 2003 rate case (see note on rate case above). Thus, Transmission does not anticipate its negotiated rate transactions being impacted by this rulemaking. At this time, Transmission cannot predict the outcome of this NOI.

On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) requiring that all cash management or money pool arrangements between a FERC regulated subsidiary and a non-FERC regulated parent must be in writing, and set forth the duties and responsibilities of cash management participants and administrators; the methods of calculating interest and for allocating interest income and expenses; and the restrictions on deposits or borrowings by money pool members. The NOPR also requires specified documentation for all deposits into, borrowings from, interest income from, and interest expenses related to these arrangements. Finally, the NOPR proposed that as a condition of participating in a cash management or money pool arrangement, the FERC regulated entity maintain a minimum proprietary capital balanc e of 30 percent, and the FERC regulated entity and its parent maintain investment grade credit ratings. The FERC held a public conference on September 25, 2002, to discuss the issues raised in comments. Representatives of companies from the gas and electric industries participated on a panel and uniformly agreed that the proposed regulations should be revised substantially and that the proposed capital balance and investment grade credit rating requirements would be excessive. On June 26, 2003, the FERC issued an Interim Rule requiring that cash management agreement be in writing, specify the duties and responsibilities of the participants, specify the methods for calculating interest and for allocating interest income and expenses, and specify any restriction on deposits or borrowing by participants. Since Transmission does not participate in a cash management pool, Transmission does not anticipate that this rule will have an impact. The Interim Rule also required that pipelines notify the FERC when their p roprietary capital ratio drops below 30 percent. In addition, in the Interim Rule the FERC sought further comments on these requirements. On October 23, 2003, the FERC issued its Final Rule, which adopted the requirement of the Interim Rule to file cash management agreements with the FERC. The Final Rule also required that pipelines must notify the FERC within 45 days after the end of each calendar quarter if their proprietary capital ratios drop below or subsequently exceed 30 percent. In its Final Rule requiring quarterly financial reporting, issued February 11, 2004, the FERC lifted the requirement to notify the FERC when proprietary capital drops below or rises above 30 percent.

In 2002, Transmission was subject to an industry wide nonpublic investigation of the FERC Form 2 (FERC’s annual report) focusing on cash management or transfers between Transmission and Enron or affiliated companies. By order issued September 8, 2003, the FERC determined that Transmission was generally in compliance. However, the FERC found that because Transmission was in a cash management pool during the time of the audit and because best management practices require a written cash management plan, Transmission ought to have a written cash management plan. On October 8, 2003, Transmission sought clarification or, in the alternative, rehearing of the order that Transmission did not have to have a written cash management plan at this time because Transmission was not now participating in a cash management pool. On December 4, 2003, the FERC issued an order granting Transmission’s request for clarification.

In April 2002, FERC and the Department of Transportation, Office of Pipeline Safety convened a technical conference to discuss how to clarify, expedite, and streamline permitting and approvals for interstate pipeline reconstruction in the event of a natural or other disaster. On January 17, 2003, FERC issued a NOPR proposing to (1) expand the scope of construction activities authorized under a pipeline’s blanket certificate to allow replacement of mainline facilities; (2) authorize a pipeline to commence reconstruction of the affected system without a waiting period; and (3) authorize automatic approval of construction that would be above the normal cost ceiling. Comments on the NOPR were filed by INGAA on February 27, 2003. On May 19, 2003 the FERC issued Order No. 633, promulgating a final rule that allo ws pipelines to start construction to replace mainline facilities without the normal 45-day notice period when immediate action is required to restore service. This rule will impact Transmission only in the event of an emergency action. In such event, Transmission expects that the rule would expedite replacement or repair of facilities, thereby reducing any service interruption period.

On November 25, 2003, the FERC issued Order No. 2004 making significant changes in the Standards of Conduct (“SOC”) governing the relationships between pipelines and Energy Affiliates. The new SOC applies to a greater number of affiliates, requires more reporting, and requires appointment of a compliance officer. On December 24, 2003, INGAA filed a request for rehearing. On January 20, 2004, the Commission issued an order granting rehearing for the purposes of further consideration, thus tolling the statutory time in which the FERC is required to act. At this time, Transmission cannot predict the final outcome of the proceeding. On February 9, 2004, Transmission made the required informational filing with regard to compliance by June 1. Certain companies plan to seek delay of the implementation to September 2004, in view of the number of pending rehearing and clarification requests. Transmission believes that the ultimate outcome of this matter will not have a materially adverse effect on the Company’s consolidated financial position, results of operations or cash flow.

On December 15, 2003, the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (“HCA”). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002, a bill signed into law on December 17, 2002. The rule requires operators to identify HCAs along their pipelines by December 2004, to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing, or direct assessment, by June 2004. Operators must risk rank their pipeline segments containing HCAs, and have the highest 50 percent assessed using one or more of these methods by December 2007. The balance must be completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the inspections. Because identification and location of all the HCAs has not been completed, and because it is impossible to determine the scope of required remediation activities prior to completion of the assessments and inspections, the cost of implementing the requirements of this regulation is impossible to determine at this time. The required modifications and inspections are estimated to range from approximately $12.0- $15.0 million per year, with remediation costs in addition to these amounts.

On December 29, 2003, the Securities and Exchange Commission (“SEC”) denied Enron’s outstanding applications for exemption under the Public Utility Holding Company Act of 1935 (“PUHCA”). Enron applied for an additional exemption on December 31, 2003. Under PUHCA, the Company would be a subsidiary of a holding company, but could be eligible for certain exemptions if such exemptions were applied for by Enron and approved by the SEC (see Note 17).

(10)Property, Plant and Equipment

The principal components of the Company's Property, Plant and Equipment at December 31, 2003 are as follows (in thousands):

Transmission Plant	$	2,725,065
General Plant		25,619
Intangible Plant		20,612
Construction Work-in-progress		35,638
Acquisition Adjustment		1,252,466
		4,059,400
Less: Accumulated depreciation and amortization		(1,072,072	)
Net Property, Plant and Equipment	$	2,987,328

(11) Other Deferred Charges

The principal components of the Company's other deferred charges at December 31, 2003 are as follows (in thousands):

Ramp-up assets, net (1)	$	12,552
Fuel tracker		6,479
Long-term receivables		77,080
Cash collateral (see Note 3) (2)		595
Receipts for escrow		7,700
Balancing tools (3)		834
Other miscellaneous		3,140
Total Other Deferred Charges	$	108,380

(1) “Ramp-up” assets is a regulatory asset Transmission was specifically allowed in the FERC certificates authorizing the Phase IV and V Expansion projects.

(2) Collateral posted to another party remains the property of the posting party, unless it defaults on the collateralized obligation.

(3) Balancing tools are a regulatory method by which Transmission recovers the costs of operational balancing of the pipelines’ system. The balance can be a deferred charge or credit, depending on timing, rate changes, and operational activities.

(12) Other Deferred Credits

The principal components of the Company's other deferred credits at December 31, 2003 are as follows (in thousands):

Accrued expansion post construction mediation costs (1)	$	4,131
Customer deposits (see Note 14)		8,859
Phase IV retainage & Phase V surety bond		471
Miscellaneous		157
Total Other Deferred Credits	$	13,618

(1) Related to significant Phase IV, V and VI expansion projects

(13)Commitments and Contingencies

From time to time, in the normal course of business, the Company is involved in litigation, claims or assessments that may result in future economic detriment. The Company evaluates each of these matters and determines if loss accruals are necessary as required by SFAS No. 5, "Accounting for Contingencies". The Company does not expect to experience losses that would be materially in excess of the amount accrued at December 31, 2003.

Transmission and Trading have filed bankruptcy related claims against Enron and other affiliated bankrupt companies totaling $220.6 million. Transmission’s claim includes rejection damages and delinquent amounts owed under certain transportation agreements, an unpaid promissory note, and other fees for services and imbalances. Subsequent to Transmission’s filing its claims, ENA’s firm transportation agreements were permanently relinquished to a creditworthy party, which significantly reduced Transmission’s rejection damages. Trading’s claim is for rejection damages on two physical/financial swaps, a gas sales contract, as well as certain delinquent amounts owed pre-petition. In July, one Enron affiliate, ENA, indicated that it did not agree with the amount of the claims and wanted to di scuss settlement/resolution. Discussion of possible settlement is underway.

On March 7, 2003, Trading filed a declaratory order action, involving a contract between it and Duke. Trading requested that the court declare that Duke breached the parties’ natural gas purchase contract by failing to provide sufficient volumes of gas to Trading. The suit seeks damages and a judicial determination that Duke has not suffered a “loss of supply” under the parties’ contract, which could, if it continued, have given rise to the right of Duke to terminate the contract at a point in the future. On April 14, 2003, Duke sent Trading a notice that the contract was terminated as of April 16, 2003 (due to Trading’s alleged failure to timely increase the amount of a letter of credit); although it disagreed with Duke’s position, Trading increased the letter of credit on April 1 5. Duke has answered and filed a counterclaim, arguing that Trading failed to timely increase the amount of a letter of credit, and that it has breached a “resale restriction” on the gas. Trading disputes that it has breached the agreement, or that any event has given rise to a right to terminate by Duke. On April 29, 2003, Duke filed to remove the case to federal court (CA03-CV-1425). On May 1, 2003, Trading notified Duke that it was in default under the Agreement, for failure to deliver the base volumes beginning April 17. However, Duke continued to refuse to perform under the contract. On May 28, 2003, Trading filed a motion to remand the case to state court. On June 2, 2003, Trading notified Duke that, because Duke had not cured its default, Trading terminated the agreement effective as of June 5, 2003. On August 8, 2003, Trading sent its final “termination payment” invoice to Duke in the amount of $187 million. On July 31, 2003, the federal court granted Trading’s motion and rem anded the case to state court. On August 18, 2003, Duke filed a Third-Party Petition against Sonatrading and Sonatrach,its Algerian suppliers (“Sonatrach”), which Trading opposed since, inter alia, even in the event of a failure to receive supplies from Algeria, Duke was required to furnish supplies to Trading for a stated period of time. On October 6, 2003, Trading filed its Amended Petition, alleging wrongful termination and containing the termination damages. In October, Sonatrach removed the case to federal court and filed a special appearance challenging jurisdiction. On November 25, 2003, Tradin g filed its Second Amended Complaint, alleging, among other things, that Duke was required to give reasonable notice to Trading to upgrade the letter of credit, before terminating the contract. On December 5, 2003, Duke filed its answer. Sonatrach’s motion to dismiss for lack of jurisdiction was filed March 2, 2004, and Duke’s response is due by March 31, 2004. Discovery is ongoing, and the judge continues to hold informal discovery in an attempt to resolve the case. On March 8, 2004, Trading made demand on PanEnergy, who, along with Duke is a signatory to the agreement, asking for PanEnergy to ensure (per the contracts) that Duke has sufficient assets to pay Trading’s claim. Because assurances were not forthcoming, on March 16, 2004, Trading filed suit against PanEnergy in state court. On March 23, 2004, Trading filed a motion for Summary Judgment against Duke, seeking a ruling that Duke was required to provide Trading with notice before terminating the agreements. This is a disputed matter, and there can be no assurance as to what amounts, if any, Trading will ultimately recover. Management believes that the amount ultimately recovered will not be materially different than the amount recognized at December 31, 2003, and that the ultimate resolution of this matter will not have a materially adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Management further believes that claims made by Duke against the Company with regard to this matter are without merit and do not constitute a liability which would require adjustment to the Company’s December 31, 2003, consolidated financial statements in accordance with SFAS No. 5.

In 1999, Transmission entered into an agreement which obligated it to various natural gas and construction projects includable in its rate base. This obligation ends July 1, 2004, and Transmission expects to incur an additional $1.1 million of potentially capitalizable costs prior to contract expiration.

The Florida Department of Transportation, Florida Turnpike Enterprise (FTE) has several turnpike widening projects in the planning stage, which may, over the next ten years, impact one or more of Transmission’s mainlines co-located in FTE right-of-way. The most immediate projects are five Sunshine State Parkway projects, which are proposed to overlap Transmission’s pipelines, for a total of approximately 22 miles. Under certain conditions, the existing agreement between Transmission and the FTE calls for the FTE to pay for any new right-of-way needed for the relocation projects and for Transmission to pay for construction costs. The actual amount of miles of pipe to be impacted ultimately, and the relocation cost and/or right-of-way cost, recoverable through rates, is either undefined at this time, du e to the preliminary stage of FTE’s planning process, or the FTE has determined not to require Transmission to relocate its line. No preliminary estimate of the cost associated with this potential relocation has been calculated, and it is not estimable at this time.

(14)Concentrations of Credit Risk and Other Financial Instruments

The Company has a concentration of customers in the electric and gas utility industries. These concentrations of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company's receivable portfolio as a whole. The Company also has a concentration of customers located in the southeastern United States, primarily within the State of Florida. Receivables are generally not collateralized. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments, deposits, or other forms of security to the Company. Transmission sough t additional assurances from customers due to credit concerns, and had customer deposits totaling $8.9 million and prepaymentsof $1.6 million for 2003. The Company's Management believes that the portfolio of Transmission’s receivables, which includes regulated electric utilities, regulated local distribution companies, and municipalities, is of minimal credit risk.

The carrying amounts and fair value of the Company's financial instruments at December 31, 2003 are as follows (in thousands):

	Carrying Amount		Estimated Fair Value
Cash and cash equivalents	$	125,226	$	125,226
Long-term debt		1,167,500		1,396,453

The carrying amount of cash and cash equivalents reasonably approximate their fair value. The fair value of long-term debt is based upon market quotations of similar debt at interest rates currently available.

(15) Comprehensive Income

Comprehensive income includes the following (in thousands):

	2003
Net income	$	76,216
Other comprehensive income:
Derivative instruments - Recognition in earnings of previously deferred (gains) and losses related to derivative instruments used as cash flow hedges		1,206
Total comprehensive income	$	77,422

(16) Accounting Pronouncements

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement requires companies to record a liability for the estimated removal costs of assets used in their business where there is a legal obligation associated with removal. The liability is recorded at its fair value, with a corresponding asset that is depreciated over the remaining useful life of the long-lived asset to which the liability relates. An ongoing expense will also be recognized for changes in the value of the liability as a result of the passage of time. The provisions of SFAS No. 1 43 are effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143, beginning January 1, 2003. A comprehensive study was made in 2003 by the Company’s Accounting, Right of Way, Legal, Internal Audit, and Operations personnel to identify all Asset Retirement Obligations that are estimable as defined in SFAS No. 143, and it has been determined that the adoption of this standard did not have a financial statement impact at this time. The Company will continue to monitor these requirements on an annual basis in the future.

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". This statement will require recognition of costs associated with exit or disposal activities when they are incurred rather than when a commitment is made to an exit or disposal plan. Examples of costs covered by this guidance include lease termination costs, employee severance costs associated with a restructuring, discontinued operations, plant closings or other exit or disposal activities. This statement is effective for fiscal years beginning after December 31, 2002, and will impact any exit or disposal activities initi ated after January 1, 2003. SFAS No. 146 has not had an impact on the Company’s financial position or results of operations.

In November 2002, the FASB issued FIN No. 45, “Guarantor’s Accounting and DisclosureRequirements for Guarantees, including Indirect Guarantees of Indebtedness of Others.” This interpretation requires that companies record a liability for all guarantees issued or modified after December 31, 2002, including financial, performance, and fair value guarantees. This liability is recorded at its fair value upon issuance, and does not affect any existing guarantees issued before December 31, 2002. While FIN No. 45 has not had an impact on the Company’s financial position or results of operations, it will impact any guarantees the Company issues in the future.

(17)Subsequent Events

On February 6, 2004, Enron filed two form U1’s with the SEC, proposing a set of conditions under which Enron would register as a holding company under PUHCA. Among other things, Enron sought an exemption for the Company under Rule 16 of the SEC’s PUHCA Rules and Regulations (17 CFR§ 250.16, “Exemption of Non-Utility Subsidiaries and Affiliates”) (The “Exemption”). On March 9, 2004, Enron amended its form U1 application filings, withdrew its application for exemption filed on December 31, 2003, and filed a form U5A, registering as a public utility holding company under PUHCA. Also on March 9, 2004, the SEC issued orders approving the applications made on the amended form U1’s and the U5A, including approval of the application for the Exemption. The result of these proceedi ngs has reconfirmed the Company’s exemption.

On January 28, 2004, Transmission extended the Waiver (see Note 3). Due to the previously unresolved exemption status of Enron under PUHCA (see Note 9), Transmission agreed to further limit its rights under the Revolver by restricting its right to issue new letters of credit. At this time Transmission cannot draw under the Revolver, nor can it issue new letters of credit.

EX-99.D

EXHIBIT 99.d

TRANSWESTERN PIPELINE COMPANY
CONDENSED BALANCE SHEETS
(In Thousands)
(Unaudited)
	September 30,			December 31,
	2004			2003
				(Restated)
ASSETS
Current Assets
Cash and cash equivalents	$	20,591		$	20,557
Accounts receivable - customers, net of allowance of $95 and $127		16,763			15,838
Transportation and exchange gas receivable		3,169			3,370
Regulatory and other assets		13,010			12,652
Total Current Assets		53,533			52,417
Property, Plant and Equipment, at Cost		1,117,005			1,067,854
Less - Accumulated depreciation and Amortization		(150,416	)		(138,759	)
Property, Plant and Equipment, Net		966,589			929,095
Deferred Assets
Deferred income taxes		-			26,637
Regulatory and other assets		78,751			88,488
Total Deferred Assets		78,751			115,125
Total Assets	$	1,098,873		$	1,096,637

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
CONDENSED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)
	September 30,		December 31,
	2004		2003
			(Restated)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable
Trade and other	$	10,203	$	2,835
Associated companies		11,126		9,618
Transportation and exchange gas payable		6,565		5,933
Notes payable and current portion of long-term debt		4,000		461,000
Reserve for regulatory and other contingencies		2,244		2,682
Accrued liabilities and other		11,468		14,296
Total Current Liabilities		45,606		496,364
Long-term Debt, net of current maturities		410,000		-
Deferred Credits and Other Liabilities
Deferred income taxes		1,338		-
Other		2,908		4,715
Total Deferred Credits and Other Liabilities		4,246		4,715
Commitments and Contingencies (Note 7)		-		-
Stockholder’s Equity
Common stock ($1 par value; 1,000 shares authorized, issued and outstanding)		1		1
Additional paid-in capital		409,191		409,191
Retained earnings		229,829		186,366
Total Stockholder’s Equity		639,021		595,558
Total Liabilities and Stockholder’s Equity	$	1,098,873	$	1,096,637

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(In Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2004			2003
Revenues
Transportation	$	133,948		$	133,978
Gas and liquids sold		24,087			15,355
Other gas revenues		1,837			223
Total Revenues		159,872			149,556
Costs and Expenses
Operating and maintenance expenses		44,409			43,367
Amortization of regulatory assets		3,475			3,475
Depreciation and amortization		17,221			18,249
Taxes, other than income taxes		6,751			9,148
Total Costs and Expenses		71,856			74,239
Operating Income		88,016			75,317
Other Income (Expense), Net
Interest and other income		586			382
Interest expense and related charges, net		(17,163	)		(30,263	)
Total Other Income (Expense), Net		(16,577	)		(29,881	)
Income Before Income Taxes		71,439			45,436
Income taxes		27,976			17,858
Net Income	$	43,463		$	27,578

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
CONDENSED STATEMENTS OF STOCKHOLDER'S EQUITY
(In Thousands)
(Unaudited)
	Nine Months Ended September 30,		Year Ended December 31,
	2004		2003
			(Restated)
Common Stock
Balance, beginning and end of period	$	1	$	1
Additional Paid-in Capital
Balance, beginning and end of period		409,191		409,191
Retained Earnings
Balance, beginning of period		186,366		147,278
Net income		43,463		39,088
Balance, end of period		229,829		186,366
Total Stockholder’s Equity	$	639,021	$	595,558

 

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2004			2003
Cash Provided by Operating Activities	$	108,182		$	66,105
Cash Flows From Investing Activities
Additions to property, plant and equipment		(53,003	)		(12,088	)
Other capital expenditures		(1,140	)		(1,499	)
Cash Used in Investing Activities		(54,143	)		(13,587	)
Cash Flows From Financing Activities
Repayment of short-term debt		(461,000	)		(49,000	)
Issuance of long-term debt		430,000			-
Repayment of long-term debt		(16,000	)		-
Debt issuance costs		(7,005	)		-
Cash Used by Financing Activities		(54,005	)		(49,000	)
Increase in Cash and Cash Equivalents		34			3,518
Cash and Cash Equivalents, Beginning of Period		20,557			39,926
Cash and Cash Equivalents, End of Period	$	20,591		$	43,444
Supplemental Cash Flow Information
Interest paid	$	12,632		$	20,705

The accompanying notes are an integral part of these financial statements.

TRANSWESTERN PIPELINE COMPANY

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of Presentation

Certain items on Transwestern’s financial statements have been reclassified in 2003 to conform with the 2004 presentation. These reclassifications had no effect on Transwestern’s previously reported net income or stockholder’s equity.

At September 30, 2004, Transwestern Pipeline Company (Transwestern) was a wholly owned subsidiary of Transwestern Holding Company, Inc. (TW Holdings), which was a wholly owned subsidiary of CrossCountry Energy, LLC (CrossCountry). CrossCountry was a wholly owned subsidiary of Enron Corp. (Enron) and certain of its subsidiary companies. Effective November 17, 2004, CrossCountry became a wholly owned subsidiary of CCE Holdings, LLC (CCE Holdings), which is a joint venture currently owned by subsidiaries of Southern Union Company (Southern Union)(50 percent), GE Commercial Finance Energy Financial Services (GE)(30 percent) and four minority interest owners (20 percent in the aggregate)(see Note 9). All of the voting interests in CCE Holdings are owned by Southern Union and GE. Also, on or about November 17, 2004, Transwestern and certain other affiliated entities were converted to limited liability companies.

The financial statements included herein are unaudited. These statements reflect all adjustments, consisting only of normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the financial position, results of operations and cash flows for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted, although Transwestern believes that the disclosures are adequate to prevent the information presented from being misleading. The results of operations for the nine months ended September 30, 2004 are not necessarily indicative of the results to be expected for the full year. These financial statements should be read in conjuncti on with Transwestern’s audited financial statements and the notes thereto for the year ended December 31, 2003.

Restatement of Financial Statements

The accompanying balance sheet as of December 31, 2003 has been restated since its original issuance to: (i) correct an error in the adoption of the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets,” (SFAS No. 142); and (ii) correct an error in the accounting for deferred taxes under SFAS No. 109, “Accounting for Income Taxes.”

In connection with adopting SFAS No. 142, effective January 1, 2002, Transwestern reclassified to goodwill a net amount of $191.2 million, and ceased amortization of this amount on a prospective basis. The reclassification to goodwill was composed of $438.8 million of excess acquisition cost over the historical net book value of Transwestern’s net assets (the Acquisition Adjustment) that arose from Enron’s acquisition of Transwestern in 1984, less the accumulated amortization and deferred tax liability. The impact of the reclassification at January 1, 2002 was a decrease in property, plant and equipment of $76.0 million, an increase in accumulated depreciation and amortization of $218.1 million and a decrease in deferred tax liability of $102.9 million. Until January 1, 2002, Transwestern reported the Acquisition Adjustment as a component of property, plant and equipment, amortized it over a life consistent with its pipeline assets, ranging from 40 to 57 years, and recorded the related deferred tax liability. Upon reevaluating the appropriate accounting and transition provisions of SFAS No. 142, Transwestern determined that the January 1, 2002 reclassification of amounts to goodwill was an error. The impact on the 2003 balance sheet and statement of stockholder’s equity of correcting that error results in: (i) a decrease in beginning retained earnings of $3.9 million; (ii) an increase in net property, plant and equipment of $282.2 million; (iii) a decrease in goodwill of $191.2 million; (iv) an increase in deferred income tax liabilities of $98.8 million; and (v) an increase in net loss of $3.9 million.

The financial statements have also been restated to correct the misapplication of SFAS No. 109 in determining the realizability of deferred tax assets. Transwestern previously provided a $23.3 million valuation allowance during 2002 against its NOLs and provided an additional $102.3 million valuation allowance during 2003. Management believed that Enron's potential near-term sale of Transwestern indicated that Transwestern's NOLs, computed on a separate-return basis, would not be utilized by Transwestern prior to its disposition. However, based on an evaluation of expected future taxable income of Transwestern, as a stand-alone taxpayer on a going-concern basis, the appropriate accounting is that such deferred tax assets were fully realizable.  The impact on the 2003 financial state ments of correcting that error results in: (i) an increase in beginning retained earnings of $23.3 million; (ii) an increase in net deferred tax assets of $102.3 million; and (iii) a decrease in income tax expense of $102.3 million with a corresponding effect of net income (loss). There is no change in Transwestern’s net cash from operating, investing or financing activities as a result of this restatement. Furthermore, Transwestern has reclassified in its 2003 balance sheet $91.2 million from receivable from parent to net deferred tax assets.

A summary of the effects of the restatements and reclassifications noted above on previously reported amounts is presented below.

	As of and for the Year Ended  December 31, 2003
	As Reported			As Restated
Balance Sheet
Property, plant and equipment, at cost	$	991,830		$	1,067,854
Accumulated depreciation and amortization		(344,904	)		(138,759	)
Property, plant and equipment, net		646,926			929,095
Goodwill		191,215			-
Deferred income tax assets		-			26,637
Total assets		1,070,226			1,096,637
Deferred income tax liabilities		91,386			-
Retained earnings		68,569			186,366
Stockholder’s equity		477,761			595,558
Total liabilities and stockholder’s equity		1,070,226			1,096,637
Statement of Stockholder’s Equity
Beginning retained earnings	$	127,882		$	147,278
Net (loss) income		(59,313	)		39,088
Stockholder’s equity		477,761			595,558

(2) Income Taxes

Tax Agreements

At December 31, 2003, Transwestern was included in the consolidated federal and state income tax returns filed by Enron. Transwestern calculates tax expense on a "separate-return basis", which requires the Company to present current and defered taxes as if it were a separate taxpayer. Effective November 17, 2004, the 1994 Tax Allocation Agreement and the March 31, 2004 Tax Sharing Agreement were terminated resulting in an amount due from Enron under the Tax Sharing Agreement, which was subsequently collected (see Note 9). Subsequent to November 17, 2004, Transwestern is no longer included in the Enron consolidated federal and state income tax returns.

Transwestern, as a member of the Enron consolidated tax group, was potentially severally liable for the tax liability of the consolidated group for the years that Transwestern was a member of the group pursuant to Treasury regulation §1.1502-6. Management believes that the Transwestern exposure to Enron’s consolidated tax liability is limited, in part because at the closing of the Purchase Agreement (see Note 9) on November 17, 2004, Transwestern, CrossCountry and the other members of the CrossCountry group were indemnified and held harmless by Enron for any federal or state income tax liabilities in excess of $5.7 million arising from Treasury regulations §1.1502-6.

(3) Long-term Debt

The Consent and Sixth Amendment to Transwestern’s November 13, 2001 credit agreement was executed on March 31, 2004. The Sixth Amendment cured the default created under that credit agreement by Enron’s registration under PUHCA and amended the credit agreement to reflect the transfer of the TW Holdings stock to CrossCountry.

On May 3, 2004 Transwestern arranged replacement financings for its short-term debt maturing in November 2004 by entering into a credit agreement that replaced the November 13, 2001 credit agreement. Transwestern obtained a $150.0 million four-year revolving credit facility and a $400.0 million five-year term loan facility, with the proceeds used to repay the existing indebtedness under the November 13, 2001 credit agreement and finance the ongoing working capital, capital expenditures and other general corporate requirements of Transwestern.

The action by the Pension Benefit Guaranty Corporation (PBGC) described below (see Note 5) constituted an ERISA Event under the terms of the May 3, 2004 credit agreement. As a result, Transwestern obtained a waiver from the requirement that it make certain representations regarding an ERISA event.

Wilmington Trust Company (Wilmington) held a beneficial interest in Transwestern by acting as a voting trustee of two voting trusts, TPC Voting Trust and THC Voting Trust. On May 24, 2004, Wilmington cancelled both of the voting trusts and no longer has a beneficial interest in Transwestern, and CrossCountry owns 100 percent of TW Holdings and TW Holdings owns 100 percent of Transwestern.

Effective November 17, 2004, Transwestern entered into new credit agreements for (i) $270.0 million of ten-year senior unsecured notes bearing interest at a fixed rate of 5.39 percent, maturing November 17, 2014, $20.0 million of which will not be drawn down until March 15, 2005; (ii) $250.0 million of twelve-year senior unsecured notes bearing interest at a fixed rate of 5.54 percent, maturing November 17, 2016; and (iii) a $230.0 million credit agreement comprised of a $100.0 million five-year term loan bearing interest at LIBOR plus 75 basis points, maturing November 17, 2009 (the Term Loan) and a $130.0 million five-year revolving credit facility bearing interest at LIBOR plus 75 basis points, due on November 17, 2009 (collectively, the Refinancing). Proceeds from the Refinancing were used to retire the May 2004 debt and to pay distributions to its equity holder totaling $241.7 million (see Note 9). The costs of the Refinancing are being amortized to interest expense ratably over the life of each debt instrument.

(4) Property, Plant and Equipment

The principal components of Transwestern’s property, plant and equipment are as follows (in thousands):

	September 30,			December 31,
	2004			2003
Transmission Plant	$	579,492		$	571,644
General Plant		26,052			30,403
Intangible Plant		31,572			26,036
Construction work-in-progress		41,122			1,004
Acquisition adjustment		438,767			438,767
Property, Plant and Equipment, at Cost		1,117,005			1,067,854
Less - Accumulated depreciation and amortization		(150,416	)		(138,759	)
Property, Plant and Equipment, Net	$	966,589		$	929,095

Included in gross property, plant and equipment is an aggregate plant acquisition adjustment of $438.8 million, which represents costs allocated to Transwestern’s transmission plant as a result of its acquisition by Enron in 1984. Currently, this amount is not considered by the Federal Energy Regulatory Commission (FERC) in determining tariff rates Transwestern may charge to its regulated customers. The unamortized balance of this adjustment is $277.7 million at September 30, 2004.

Intangible assets from above include the following (in thousands):

	September 30,			December 31,			Weighted-average amortization
	2004			2003			period (in years)
Intangible Assets:
Software licenses	$	21,293		$	15,757			10
Contribution in aid of construction		10,279			10,279			12
Intangible Assets, at Cost		31,572			26,036
Less - Accumulated depreciation and amortization		(16,957	)		(12,323	)
Intangible Assets - Net	$	14,615		$	13,713

Amortization of intangible assets over the next five years is estimated to be recognized as follows (in millions):

Fiscal year:	Amount
2004 (remaining 3 months)	$	0.8
2005		2.7
2006		2.0
2007		2.3
2008		2.0

(5) Employee Benefit Plans

Transwestern recognized an additional $2.7 million current liability for the termination of the Enron Corp. Cash Balance Plan (the Cash Balance Plan) by a charge to operating and maintenance expenses in June 2004. The additional charge reflects the most recent obligation expected to be allocated to Transwestern based on a review by third party consultants. In June 2004, the PBGC filed a complaint in the United States District Court for the Southern District of Texas to terminate the Cash Balance Plan and other pension plans of Enron debtor companies and affiliates, (the Plans). If the PBGC successfully terminated the Plans in this suit, each member of the Enron “controlled group of corporations” within the meaning of Section 414 of the Tax Code, and certain other Enron affiliates, would be jointly and severally liable, under Title IV of ERISA, for the Plans’ unfunded benefit liabilities. In addition, Transwestern, as a former participating employer in certain Enron benefit plans, may have indemnity obligations in favor of committee members and others under certain Enron benefit plans that are the subject of litigation asserting, among other claims, breaches of fiduciary duty. Under certain circumstances, the PBGC may enforce ERISA Title IV liability through the imposition of liens. On September 10, 2004, Enron agreed to deposit $321.8 million in an escrow account to cover, among other things, the unfunded benefit liabilities relating to the Plans. The escrow account was funded with a portion of the proceeds from Enron’s sale of CrossCountry. Under the Purchase Agreement (see Note 9), Transwestern is not required to make further contributions to the Cash Balance Plan, beyond its accrued liability, after the date of the Purchase Agreement. Although there can be no assurance that Transwestern will not have further obligations with respect to the Plans or other Enron benefit plans, Transwestern does not believe that the ultimate resolution of these matters will have a material adverse effect on its financial position, results of operations or cash flows. Under the Purchase Agreement (see Note 9) Enron agreed (subject to a cap) to indemnify and hold harmless Transwestern, CrossCountry and certain other members of the CrossCountry group for, among other things, any joint and several liability arising under Title IV of ERISA or due to Transwestern’s status as a participating employer in certain Enron benefit plans, including the Cash Balance Plan.

Transwestern is a participating employer in the Enron Gas Pipelines Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to former employees of Transwestern and certain other Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp. Medical Plan for Inactive Participants. Enron has made the determination that it will partition the Trust and distribute the assets and liabilities of the Trust among the participating employers of the Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer. The Trust Committee has final approval on allocation methodology for the Trust assets. Enron filed a motion, which has been stayed, which provides th at each participating employer expressly assumes liability for its allocable portion of retiree benefits and releases Enron from any liability with respect to the Trust in order to receive the assets of the Trust.

(6) Rate Matters and Regulatory Issues

On February 6, 2004, Enron filed two form U1’s with the Securities and Exchange Commission (SEC), proposing a set of conditions under which Enron would register as a holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). On March 9, 2004, Enron amended its form U1 application filings, withdrew its application for exemption filed on December 31, 2003, and filed a form U5A, registering as a public utility holding company under PUHCA. Also on March 9, 2004, the SEC issued orders approving the applications made on the amended form U1’s and the U5A. At that time Transwestern became subject to PUHCA as a “subsidiary company” of a “registered utility holding company.” As of November 17, 2004, as a result of the sale of Transwestern by Enron to CCE Holdings, Transwestern is no longer a subsidiary of a registered utility holding company (see Note 9).

Transwestern filed on April 8, 2004 an application with the FERC for a proposed expansion project (Expansion Project) that will increase incremental capacity by 375,000 dekatherms per day on the San Juan Lateral from the Blanco Hub, located in San Juan County, New Mexico, to the Gallup area located at the interconnection of the San Juan Lateral and Transwestern’s mainline. The Expansion Project will expand Transwestern’s natural gas transmission system through the construction of approximately 72.6 miles of pipeline looping on the existing San Juan Lateral and causing Transwestern to abandon, install, and modify facilities at three existing compressor stations for additional compression totaling 20,000 horsepower. The Expansion Project was approved by the FERC in July 2004, and the facilities are expe cted to be in-service by mid-2005 at an estimated cost to construct of $145.7 million.

In November 2004, the FERC issued an industry-wide Proposed Accounting Release that, if enacted as written, would require pipeline companies to expense rather than capitalize certain costs related to mandated pipeline integrity programs. The accounting release is proposed to be effective January 2005 following a period of public comment on the release. Transwestern already expenses such costs.

(7) Commitments and Contingencies

From time to time, in the normal course of business, Transwestern is involved in litigation, claims or assessments that may result in future economic detriment. Transwestern evaluates each of these matters and determines if loss accruals are necessary as required by Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies.” Transwestern does not expect to experience losses that would be materially in excess of the amounts accrued at September 30, 2004.

Legal Proceedings

In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293 (D. Wy), previously Civil Action Nos. 97-D-1421 (D. Colo.) and 97-2087 (E.D. La.) and other consolidated cases. The plaintiff has filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. Transwestern believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which is filed with and approved by FERC. Transwestern’s legal exposure, if any, related to the ultimate resolution of this matter is not currently determinable.

Transwestern Pipeline Company v. Burlington Northern and Santa Fe Railway Company, et al (Case No. CV-2003-180 II, 11^th Judicial District Court, McKinley County, New Mexico). Transwestern filed suit against Burlington Northern (Burlington) on May 22, 2003 for damages incurred as a result of a Burlington train derailment on October 29, 2000 and subsequent repair activities. Transwestern filed an amended complaint to specifically include Burlington’s contractors. Burlington has joined Burlington’s contractors and the contractor’s insurers. Discovery is ongoing. This is an insured matter and therefore the claim is being pursued by and on behalf of Transwestern and Transwestern’s underwriters. Transwestern has received payment in the amount of $0.4 million from the underwriters for the insured portion of the claim. Transwestern is pursuing the deductible of $0.5 million, among other damages. The matter was settled in principle at mediation on January 28, 2005.

Transwestern is managing three threatened trespass actions related to right of way (ROW) on Tribal or allottee land. The first action involves an agreement with the United States Department of the Interior, Bureau of Indian Affairs (BIA) covering 44 miles of ROW on a total of 69 Navajo allotments. This ROW agreement expired on January 1, 2004. One allottee, Mr. Leon Gibson, sent a letter dated January 16, 2004 to the BIA claiming Transwestern is trespassing. Discussions are ongoing with the BIA to approve the renewal application, which was filed in October 2002. The second action involves a 1990 Grant of Easement and Right of Way by the Secretary of the Interior covering 6.6 miles of Southern Ute land assigned by Northwest Pipeline Corporation (Northwest Pipeline) to Transwestern in 1996. Application was made t o the BIA for approval of that assignment, but no action was taken. On May 27, 2003 and September 2, 2003, counsel for the Southern Ute Tribe sent letters to Transwestern alleging trespass. Under the operative regulations and the underlying agreements, Transwestern believes that the consent of the Tribe is not required to assign the ROW grant from Northwest Pipeline to Transwestern. The third action concerns 5,100 feet of ROW on private allotments within the Laguna Pueblo expired on December 28, 2002. Transwestern received a letter dated March 19, 2003 from the BIA on behalf of the two allottees asserting trespass. Transwestern’s costs and legal exposures related to this matter are not currently determinable.

Rates and Regulatory Matters

On August 1, 2002, the FERC issued an Order to Respond (August 1 Order) to Transwestern. The order required Transwestern, within 30 days of the date of the order, to provide written responses stating why the FERC should not find that: (i) Transwestern violated FERC's accounting regulations by failing to maintain written cash management agreements with Enron; and (ii) the secured loan transactions entered into by Transwestern in November 2001 were imprudently incurred and why the costs arising from such transactions should be passed on to ratepayers. Transwestern filed a response to the August 1 Order and subsequently entered into a settlement with the FERC staff that resolved, as to Transwestern, the issues raised by the August 1 Order. The FERC approved this settlement; however, a group of Transwestern’s customers filed a request for clarification and/or rehearing of the FERC order approving the settlement. This customer group claimed that there is an inconsistency between the language of the settlement agreement and the language of the FERC order approving the settlement. This alleged inconsistency relates to Transwestern’s ability to pass through to its ratepayers the costs of any replacement or refinancing of the secured loan transactions entered into by Transwestern in November 2001. Transwestern filed a response to the customer group’s request for rehearing and/or clarification and this matter is currently awaiting FERC action.

On December 15, 2003, the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (HCA). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002, a bill signed into law on December 17, 2002. The rule requires operators to identify HCAs along their pipelines by December 2004, and to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing, or direct assessment, by June 2004. Operators must risk rank their pipeline segments containing HCAs, and have the highest 50 percent assessed using one or more of these methods by December 2007. The balance must be completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the inspections. Because identification and location of all the HCAs has not been completed, and because it is impossible to determine the scope of required remediation activities prior to completion of the assessments and inspections, the cost of implementing the requirements of this regulation is impossible to determine at this time. The required modifications and inspections are estimated to range from approximately $12.0 - $15.0 million per year, with remediation costs in addition to these amounts. A provision in the Settlement described above provides for recovery of some added assessment and repair/replacement capital costs via a special capital surcharge, if certain conditions are met.

Environmental Matters

Transwestern is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenses. These increased operating expenses are not expected to have a material impact on Transwestern’s financial position or results of operations.

Transwestern conducts soil and groundwater remediation at a number of its facilities. During the nine months ended September 30, 2004, these costs totaled $1.2 million, $0.8 million of which were capitalized to transmission plant, and $0.4 of which were charged to operating and maintenance expenses.

Transwestern incurred, and continues to incur, certain costs related to polychlorinated biphenyls (PCBs) that migrated into customer’s facilities. These PCBs were originally introduced into the Transwestern system through use of a PCB-based lubricant in the late 1960’s and early 1970’s. Because of the continued detection of PCBs in the customer’s facilities downstream of Transwestern’s Topock and Needles stations, Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities during the nine months ended September 30, 2004 totaled $0.4 million. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former cust omers, and accordingly, no accrual has been established for these costs at September 30, 2004. However, such future costs are not expected to have a material impact on Transwestern’s financial position or results of operations or cash flows.

Capital Commitments and Purchase Obligations

One of Transwestern’s affiliates participated in the 1992 acquisition of a license to operate a natural gas pipeline in Argentina. Transwestern guaranteed certain limited performance obligations of that affiliate to certain joint venture partners of that affiliate and has agreed to provide technical support to that affiliate in connection with the operation of the pipeline. In addition, at the time of the acquisition, Transwestern was deemed to be part of the “economic group” of Enron-controlled companies and Transwestern’s net worth was used to satisfy certain net worth requirements established by the Argentine government relating to the acquisition of the license to operate such pipeline. Upon the closing of the Purchase Agreement (see Note 9) on November 17, 2004, Transwestern and certain of its affiliates were indemnified and held harmless by Enron against third-party claims relating to Transwestern’s participation in this project, other than liabilities that result from any action or inaction by Transwestern that is not in accordance with certain performance standards agreed upon by Enron and Transwestern’s parent company. In addition, on April 16, 2004, the joint venture participants in the project granted Transwestern a release from any liability of Transwestern to such participants as a result of Transwestern being considered part of the Enron economic group. This release has been approved by the bankruptcy court.

(8) Related Party Transactions

Effective April 1, 2004, services previously provided by bankrupt Enron affiliates to Transwestern pursuant to an allocation methodology ordered by the Bankruptcy Court for the Southern District of New York (Bankruptcy Court) are now covered by and charged under the terms of the Transition Services Supplemental Agreement (TSSA). The total costs are not materially different than those previously charged.

Transwestern has entered into compression services agreements with Enron Compression Services Company (ECS), an Enron affiliate that is not in bankruptcy. The agreements require Transwestern to pay ECS a compression service charge in cash and in-kind to provide electric horsepower capacity and related horsepower hours to be used to operate the Bisti, Bloomfield, and Gallup electric compressor stations located in New Mexico. ECS is required to pay Transwestern a monthly fee to operate and maintain the facilities. Transwestern and ECS entered into a Purchase and Settlement Agreement and Mutual Release (the Purchase and Settlement Agreement) dated April 30, 2004. The Purchase and Settlement Agreement (i) caused the sale of certain motor and drive systems of ECS to Transwestern; and (ii) amended and restated certai n compression services agreements between Transwestern and ECS. Effective December 1, 2004, ECS assigned all of its interest in the compression services agreements to Paragon ECS Holdings, LLC, a non-affiliated entity.

Effective November 17, 2004, the 1994 Tax Allocation Agreement and the March 31, 2004 Tax Sharing Agreement between affiliates of Transwestern and Enron were terminated, the remaining tax receivable due from Enron under the Tax Sharing Agreement was collected and Transwestern is no longer a member of the Enron Consolidated Group (see Note 9).

(9) Subsequent Events

Effective November 17, 2004, CrossCountry was acquired by CCE Holdings. At or about the time of the acquisition, among other things:

·   Transwestern, along with certain other affiliated entities, was converted to a limited liability company (LLC).  As a single-member LLC, Transwestern is a disregarded entity for federal income tax purposes, and will be included in the Federal Partnership tax return of CCE Holdings;

·   CrossCountry transferred to ONEOK, Inc. its interests in Northern Plains Natural Gas Company, LLC, Pan Border Gas Company, LLC and NBP Services, LLC, and CCE Holdings entered into a six-month Transition Services Agreement with ONEOK;

·   Transwestern refinanced its outstanding debt and paid distributions to its equity holder as described below;

·   Transwestern and Enron terminated the 2004 Tax Sharing Agreement and the 1994 Tax Allocation Agreement, with each party releasing the other from any further rights, obligations or liabilities (see Note 2).  In connection with this termination, Enron paid Transwestern $62.5 million, representing the net amount due for, among other things, the remaining tax receivable that arose under this agreement in prior years;

·   Transwestern’s rights, title and interest in its claims against Enron and certain of its bankrupt subsidiaries, totaling approximately $824.6 million, were transferred in the form of a dividend to its equity owners prior to the acquisition of CrossCountry by CCE Holdings. This dividend had no effect on Transwestern’s financial statements as such rights, title, interest and claims had been written off in prior years;

·   Under a Guaranty Agreement with Enron and certain of its subsidiaries, CrossCountry and certain of its subsidiaries (including Transwestern) jointly and severally guaranteed all obligations of CCE Holdings arising under the Purchase Agreement, as amended (described below).

Effective November 17, 2004, Transwestern entered into credit agreements for (i) $270.0 million of ten-year senior unsecured notes bearing interest at a fixed rate of 5.39 percent, maturing November 17, 2014, $20.0 million of which will not be drawn down until March 15, 2005; (ii) $250.0 million of twelve-year senior unsecured notes bearing interest at a fixed rate of 5.54 percent, maturing November 17, 2016; and (iii) a $230.0 million credit agreement comprised of a $100.0 million five-year term loan bearing interest at LIBOR plus 75 basis points, maturing November 17, 2009 (the Term Loan) and a $130.0 million five-year revolving credit facility bearing interest at LIBOR plus 75 basis points, due on November 17, 2009 (collectively, the Refinancing). Proceeds from the Refinancing were used by Transwestern to re tire the May 2004 debt and to pay distributions to its equity holder totaling $241.7 million. No principal payments are required under any of the new debt agreements prior to their respective maturity dates. The Term Loan is collateralized with substantially all of the assets and the capital stock of Transwestern.

Effective December 16, 2004, Citicorp North America, Inc. (Citicorp) claimed, in its capacity as the Paying Agent and Co-Administrative Agent, that any recovery in the litigation captioned Enron Corp. et al. v. Citigroup, Inc. et al. (In re Enron Corp. et al.), adv. No. 03-93611 (AJG), ch. 11 no. 01-16034 (AJG) (Bankr. S.D.N.Y. filed Dec. 1, 2003) (the Litigation), together with legal fees and expenses incurred by Citicorp in defending the Litigation, would be indemnity obligations (the Obligations) of Transwestern under its Credit Agreement dated November 13, 2001. Under the terms of the Purchase Agreement, dated June 24, 2004 (as amended by that certain Amendment No. 1 to Purchase Agreement, dated September 1, 2004, and that certain Amendment No. 2 to Purchase Agreement, dated November 11, 2004), CCE Holdings and certain of its subsidiaries (including Transwestern) are indemnified against the Obligations by Enron and certain of its subsidiaries. Accordingly, the Company does not believe that it has any material liability from Citicorp’s claims.

EX-99.E

EXHIBIT 99.e

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands)
(Unaudited)
	September 30,			December 31,
	2004			2003
ASSETS
Current Assets
Cash and cash equivalents	$	260,685		$	125,226
Accounts receivable - trade and other, net of allowance of $74 and $77		53,733			39,713
Price risk management assets		4,287			15,024
Materials and supplies		2,991			2,915
Other		1,959			4,294
Total Current Assets		323,655			187,172
Property, Plant and Equipment, at Cost
Completed plant		4,079,643			4,023,762
Construction work-in-progress		5,645			35,638
Property, Plant and Equipment, at Cost		4,085,288			4,059,400
Less - Accumulated depreciation and amortization		(1,117,318	)		(1,072,072	)
Property, Plant and Equipment, net		2,967,970			2,987,328
Deferred Charges
Unamortized debt expense		7,863			9,051
Price risk management assets		30,459			58,492
Other		109,245			108,380
Total Deferred Charges		147,567			175,923
Total Assets	$	3,439,192		$	3,350,423

 

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(In Thousands, Except Share Data)
(Unaudited)
	September 30,			December 31,
	2004			2003
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable
Trade and other	$	11,666		$	30,396
Affiliated companies		18,326			20,086
Accrued interest		33,869			19,054
Accrued Income taxes		23,040			1,148
Accrued taxes, other than income		25,686			10,349
Price risk management liabilities		3,603			25,136
Exchange gas imbalances, net		13,779			12,320
Current maturities of long-term debt		256,159			256,159
Other		121			283
Total Current Liabilities		386,249			374,931
Long-term Debt, net of current maturities		902,727			908,972
Deferred Credits and Other Liabilities
Deferred income taxes		714,914			676,341
Price risk management liabilities		25,086			80,446
Other		20,205			13,618
Total Deferred Credits and Other Liabilities		760,205			770,405
Commitments and Contingencies (Notes 7 and 9)		-			-
Stockholders’ Equity
Common stock ($1 par value; 1,000 shares authorized, issued and outstanding)		1			1
Additional paid-in capital		634,271			634,271
Accumulated other comprehensive income		(16,341	)		(17,247	)
Retained earnings		772,080			679,090
Total Stockholders’ Equity		1,390,011			1,296,115
Total Liabilities and Stockholders’ Equity	$	3,439,192		$	3,350,423

            The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(In Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2004			2003
Revenues
Gas transportation, net	$	355,285		$	332,914
Gas sales		40,130			91,570
Total Revenues		395,415			424,484
Costs and Expenses
Natural gas purchased		44,499			84,843
Operations and maintenance		67,875			77,278
Depreciation		35,888			32,604
Amortization		15,048			15,048
Taxes, other than income taxes		23,147			21,336
Total Costs and Expenses		186,457			231,109
Operating Income		208,958			193,375
Other Income (Expense)
Interest expense, net		(73,494	)		(79,236	)
Allowance for funds used during construction		834			5,419
Other, net		14,776			(24,308	)
Total Other Income (Expense)		(57,884	)		(98,125	)
Income Before Income Taxes		151,074			95,250
Income Taxes		58,084			37,154
Net Income	$	92,990		$	58,096

 

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In Thousands)
(Unaudited)
	Nine Months Ended September 30,			Year Ended December 31,
	2004			2003
Common Stock
Balance, beginning and end of period	$	1		$	1
Additional Paid-in Capital
Balance, beginning and end of period		634,271			634,271
Accumulated Other Comprehensive Income (Loss):
Balance, beginning of period		(17,247	)		(18,453	)
Recognition in earnings of previously deferred losses related to derivative instruments used as cash flow hedges		906			1,206
Balance, end of period		(16,341	)		(17,247	)
Retained Earnings
Balance, beginning of period		679,090			602,874
Net income		92,990			76,216
Balance, end of period		772,080			679,090
Total Stockholders’ Equity	$	1,390,011		$	1,296,115

 

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
	Nine Months Ended
	September 30,
	2004			2003
Cash Provided by Operating Activities	$	173,834		$	204,273
Cash Flows From Investing Activities
Additions to property, plant and equipment, net		(32,708	)		(116,867	)
Allowance for funds used during construction		833			5,418
Cash Used in Investing Activities		(31,875	)		(111,449	)
Cash Flows From Financing Activities
Repayment of long-term debt		(6,500	)		(6,500	)
Increase in Cash and Cash Equivalents		135,459			86,324
Cash and Cash Equivalents, Beginning of Period		125,226			114,674
Cash and Cash Equivalents, End of Period	$	260,685		$	200,998
Supplemental Cash Flow Information
Interest	$	56,533		$	62,127
Income taxes (refunded) paid		(2,382	)		16,385

The accompanying notes are an integral part of these financial statements.

CITRUS CORP. AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of Presentation and Significant Accounting Policies

At September 30, 2004, the stock of Citrus Corp. was owned 50 percent by CrossCountry Citrus Corp., a wholly owned subsidiary of CrossCountry Energy, LLC (CrossCountry), and 50 percent by El Paso Citrus Holdings, Inc., a wholly owned subsidiary of Southern Natural Gas Company. CrossCountry was a wholly owned subsidiary of Enron Corp. (Enron) and certain of its subsidiary companies. Effective November 17, 2004, CrossCountry became a wholly owned subsidiary of CCE Holdings, LLC (CCE Holdings), which is a joint venture owned by subsidiaries of Southern Union Company (Southern Union)(50 percent), GE Commercial Finance Energy Financial Services (GE)(30 percent) and four minority interest owners (20 percent in the aggregate)(se e Note 11). All of the voting interests in CCE Holdings are owned by Southern Union and GE.

The accompanying interim financial statements include Citrus Corp. and its wholly owned subsidiaries, Florida Gas Transmission Company (Transmission), Citrus Trading Corp. (Trading) and Citrus Energy Services, Inc. (CESI)(collectively, the Company), and are unaudited. These statements reflect all adjustments, consisting only of normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the financial position, results of operations and cash flows for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures are adequate to prevent the information presented from being misle ading. The results of operations for the nine months ended September 30, 2004 are not necessarily indicative of the results to be expected for the full year. These financial statements should be read in conjunction with the Company’s audited consolidated financial statements and the notes thereto for the year ended December 31, 2003.

Recent Accounting Pronouncements

In November 2004, the Federal Energy Regulatory Commission (FERC) issued an industry-wide Proposed Accounting Release that, if enacted as written, would require pipeline companies to expense rather than capitalize certain costs related to mandated pipeline integrity programs. The accounting release is proposed to be effective January 2005 following a period of public comment on the release. The Company is currently reviewing the release and has not determined what impact this release will have on its consolidated financial statements.

On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was signed. The Act raises a number of issues with respect to accounting for income taxes. On December 21, 2004, the Financial Accounting Standards Board (FASB) issued a FASB Staff Positions (FSP) regarding the accounting implications of the Act related to the deduction for qualified domestic production activities (FSP FAS 109-1). The guidance in the FSP applies to financial statements for periods ending after the date the Act was enacted.

In FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the FASB decided that the deduction for qualified domestic production activities should be accounted for as a special deduction under Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” and rejected an alternative view to treat it as a rate reduction. Accordingly, any benefit from the deduction should be reported in the period in which the deduction is claimed on the tax return. In most cases, a company’s existing deferred tax balances will not be impacted at the date of enactment. For some companies, the deduction could have an impact on their effect ive tax rate and, therefore, should be considered when determining the estimated annual rate used for interim financial reporting. The Company is currently evaluating the impact, if any, of this FSP on its consolidated financial statements.

In Statement of Financial Accounting Standards (SFAS) No. 153, the FASB modified the existing guidance on accounting for nonmonetary transactions in Accounting Principals Board Opinion No. 29, “Accounting for Nonmonetary Transactions,” to eliminate an exception under which certain exchanges of similar productive nonmonetary assets were not accounted for at fair value. SFAS No. 153 instead provides a general exception for exchanges of nonmoneary assets that do not have commercial substance. This statement must be applied to nonmonetary assets exchanges occurring in fiscal periods beginning after June 15, 2005. The Company is currently evaluating the impact, if any, of this statement on its consolidated financial statements.

(2) Long-Term Debt and Other Financing Arrangements

On April 1, 2004, Transmission paid $6.5 million due annually under its 9.75 percent Notes. On November 1, 2004, Transmission paid the $250.0 million principal and accrued but unpaid interest related to its 8.63 percent Notes due 2004, which was classified as a current obligation in the accompanying balance sheet at September 30, 2004. This $256.5 million in current maturities was funded primarily from working capital. Under the terms of its debt agreements, Transmission may incur additional debt to refinance maturing obligations if the refinancing does not increase aggregate indebtedness, and thereafter, if Transmission and the Company’s consolidated debt does not exceed specific debt to total capitalization ratios, as defined in certain debt instruments.

On August 13, 2004, Transmission replaced the 2001 Revolver with a 3-year $50.0 million revolving credit facility (the 2004 Revolver). The 2004 Revolver has a lower LIBOR margin and fewer restrictive covenants than the 2001 Revolver, but contains restrictions that, among other things, limit the incurrence of additional debt and the sale of assets. The committed amount under this agreement was increased on November 15, 2004 to $175.0 million, and Transmission drew $135.0 million on November 17, 2004 to help fund a $140.0 million dividend by the Company to its equity owners (see Note 11). On December 31, 2004, the amount drawn under the 2004 Revolver was $117.0 million with a weighted average interest rate of 3.24 percent (based on LIBOR plus 0.95 percent).

Transmission had an aggregate $0.6 million in letters of credit under the 2001 revolving credit agreement (2001 Revolver) outstanding at December 31, 2003. During May 2004, approximately $0.5 million was released and the remainder was converted into surety bonds. There were no outstanding letters of credit at September 30, 2004.

(3)      Derivative Instruments

At September 30, 2004, the fair value of price risk management assets and liabilities was $34.8 million and $28.7 million, respectively. At December 31, 2003, the fair value of price risk management assets and liabilities was $73.5 million and $105.6 million, respectively. The Company performs a quarterly revaluation on the carrying balances, based on management’s best estimate of the value of the underlying contracts, that is reflected in current earnings. The impact to earnings from revaluation, mostly due to price fluctuations and contract status, was a loss of $11.0 million and $16.1 million for the nine months ended September 30, 2004 and 2003, respectively, and included in other income (expense), net in the accompanying statement of operations.

Prior to the Enron bankruptcy, Enron North America Corp. (ENA) was a principal counterparty to Trading’s gas purchase and sale agreements (including swaps). ENA has rejected these contracts in bankruptcy. A pre-petition gas purchase payable to ENA of $12.4 million was reversed in December 2003 when it was determined that the Company had a right of offset against claims for pre-petition receivables. Pursuant to an existing operating agreement, which was rejected by ENA in 2003 but under which an El Paso Corporation (El Paso) affiliate is still performing, an affiliate of El Paso was required to buy gas, purchased from a significant third party, that exceeded the requirements of Trading’s existing sales contracts. Under this third-party contract, gas was purchased primarily at rates based upon an indexed oil p rice formula. This gas was then sold primarily at market rates for gas. On April 16, 2003, the significant third-party supplier terminated the supply contract. Trading currently only purchases, from third parties at market rates, the requirements to fulfill existing sales contracts. As a result of these developments, the cash flow stream became dependent on variable pricing, whereas before Enron’s bankruptcy, the cash flow stream was fixed (under certain swaps). During the fourth quarter of 2004, the Company liquidated its remaining derivative contract without a material impact on the consolidated statement of operations.

Due to a dispute (see Note 9) during 2003, Duke Energy LNG Sales, Inc. (Duke) purported to terminate and discontinued performance under a natural gas purchase and supply contract between it and Trading, and Trading subsequently terminated the contract. As a result of this contract termination during 2003, Trading discontinued the application of fair market value accounting for this contract, and wrote off the value of the related price risk management assets as a charge to Other Income (Expense), net in the accompanying statement of income for the nine months ended September 30, 2003. Pursuant to the terms of the contract, Trading issued to Duke, the counterparty, a termination invoice for approximately $187.0 million during the 2003 period. As a result of the ongoing litigation regarding this matter, the termi nation invoice amount was recognized, net of appropriate reserves and certain related matters, including bankruptcy claims held by Trading against ENA, as an offsetting gain to Other Income (Expense), net and is presented as a net long term receivable in Other Deferred Charges of $66.9 million and $72.5 million at September 30, 2004 and December 31, 2003, respectively (see Note 9).

(4) Employee Benefit Plans

During 2003, the employees of the Company were covered under Enron’s employee benefit plans. The Company’s participation in the Enron benefit plans terminated during November 2004.

Enron maintained a pension plan that was a noncontributory defined benefit plan, the Enron Corp. Cash Balance Plan (the Cash Balance Plan), covering certain Enron employees in the United States and certain employees in foreign countries. The basic benefit accrual was 5 percent of eligible annual base pay. Pension expense charged to the Company by Enron for the nine months ended September 30, 2004 and 2003 was $0.4 million and $1.6 million, respectively.

In June 2004, the Pension Benefit Guaranty Corporation (PBGC) filed a complaint in the United States District Court for the Southern District of Texas to terminate the Cash Balance Plan and other pension plans of Enron debtor companies and affiliates (the Plans). Because the Company is not a part of an Enron “controlled group of corporations” within the meaning of Section 414 of the Tax Code, if the Plans were to be terminated pursuant to the PBGC action or in other than standard terminations, the Company would be liable for only its proportionate share of any underfunding that may exist in the Cash Balance Plan at the time of such termination, though there can be no assurance that the PBGC might not take a different position. In addition, Transmission, as a former participating employer in certain En ron benefit plans, may have indemnity obligations in favor of committee members and others under certain Enron benefit plans that are the subject of litigation asserting, among other claims, breaches of fiduciary duty. Under certain circumstances, the PBGC may enforce ERISA Title IV liability through the imposition of liens. On September 10, 2004, Enron agreed to put $321.8 million in an escrow account to cover, among other things, the unfunded benefit liabilities related to the Plans. The escrow account was funded with a portion of the proceeds from Enron’s sale of CrossCountry. Based on the current status of the Cash Balance Plan termination cost and the amount expected to be allocated to the Company as its proportionate share of the plan’s termination liability, the Company continues to believe its accruals related to this matter are adequate but not excessive. Although there can be no assurance that amounts ultimately allocated to and paid by the Company will not be materially different, we do not believe that the ultimate resolution of these matters will have a materially adverse effect on the Company’s consolidated financial position or cash flows, but it could have significant impact on the results of operations in future periods.

Enron provides certain post-retirement medical, life insurance and dental benefits to eligible employees and their eligible dependents. The net periodic post-retirement benefit cost charged to the Company by Enron for the nine months ended September 30, 2004 and 2003 was $0.5 million and $0.9 million, respectively. Substantially all of these amounts relate to Transmission and are being recovered through rates.

Certain retirees of Transmission were covered under a deferred compensation plan managed and funded by Enron subsidiaries, one previously sold and the other now in bankruptcy. This matter has been included as part of the claim filed by Transmission in bankruptcy against Enron and other affiliated bankrupt companies. At December 31, 2004, Transmission had not conceded that it had a legal responsibility to fund the obligations to these certain retirees, but had approved certain payments in the past in order to avoid litigation. If such obligation were deemed to be a liability to Transmission, the range of exposure is between $0 and approximately $2.1 million at September 30, 2004. Transmission and Enron agreed in principle to a settlement with regard to Transmission’s claims, resulting in an allowed claim by Transmission of approximately $3.4 million against Enron. Documents are currently being prepared, however, due to the preliminary status of this matter, management cannot estimate the likelihood of the ultimate outcome of this matter.

Transmission is a participating employer in the Enron Gas Pipelines Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to former employees of Transmission and certain other Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp. Medical Plan for Inactive Participants. Enron has made the determination that it will partition the Trust and distribute the assets and liabilities of the Trust among the participating employers of the Trust on a pro rata basis according to the contributions and liabilities associated with each participating employer. The Trust Committee has final approval on allocation methodology for the Trust assets. Enron filed a motion, which has been stayed, which provides th at each participating employer expressly assumes liability for its allocable portion of retiree benefits and releases Enron from any liability with respect to the Trust in order to receive the assets of the Trust.  Management believes that an adverse outcome with respect to this matter is remote.

(5) Major Customers

Approximate revenues from individual customers exceeding 10 percent of total revenues for the nine months ended September 30, 2004 and 2003 were as listed below (in millions):

	Nine Months Ended
Customers	September 30, 2004		September 30, 2003
Florida Power & Light Company	$	142.1	$	139.4

At September 30, 2004 and December 31, 2003 the Company had receivables of approximately $16.1 million and $15.1 million, respectively, from Florida Power & Light Company.

(6) Related Party Transactions

In December 2001, Enron and certain of its subsidiaries filed voluntary petitions for protection under Chapter 11 of the Bankruptcy Code. The Company was not included in the bankruptcy filing, and Management believes that the Company will continue to be able to meet its own operational and administrative service obligations. At December 31, 2003, Transmission and Trading had aggregate outstanding claims with the Bankruptcy Court against Enron and affiliated bankrupt companies of $220.6 million. Of these claims, Transmission and Trading filed claims totaling $68.1 million and $152.5 million, respectively. Transmission and Trading claims pertaining to contracts rejected by ENA were $21.4 million and $152.3 million, respectively (see Note 9). Transmission’s claims against ENA were reduced by approximately $21 .2 million when a third party took assignment of ENA’s transportation contracts.

During the periods presented, the Company reimbursed certain corporate administrative expenses to Enron and its affiliates, including administrative, legal, compliance, and pipeline operations emergency services, under an operating agreement between an Enron affiliate and the Company. The agreement expired on June 30, 2001 and has not been extended; however, Enron subsidiaries continued to provide services under the terms of the original operating agreement. For the nine months ended September 30, 2004 and 2003, the Company charged operations and maintenance expenses of approximately $10.7 million and $10.2 million, respectively, for such operating expenses.

Services provided by bankrupt Enron affiliates were allocated to the Company during the periods presented pursuant to a Bankruptcy Court ordered allocation methodology. Under that methodology, the Company was obligated to pay allocated amounts, subject to certain terms and conditions. Consistent with these terms and conditions, the Company accrued and paid the full amount for services it received directly from the bankrupt Enron affiliates. Indirect Enron service allocations were capped commensurate with 2001 levels. Effective April 1, 2004, services previously provided by bankrupt Enron affiliates to the Company pursuant to an allocation methodology ordered by the Bankruptcy Court are now covered by and charged under the terms of the Transition Services Supplemental Agreement (TSSA). The total costs are not ma terially different than those previously charged. During the nine months ended September 30, 2004, the Company recognized $1.3 million for indirect services and $6.3 million for direct services. During the nine months ended September 30, 2003, the Company recognized $1.6 million for indirect services and $6.8 million for direct services.

During the periods presented, Trading sold natural gas and Transmission provided natural gas transportation services to El Paso affiliates at rates equal to rates charged to non-affiliated customers in the same class of service. Revenues related to these gas sales and transportation services were approximately $0.1 and $2.9 million, respectively, for the nine months ended September 30, 2004. Revenues related to these gas sales and transportation services were approximately $9.2 and $4.8 million, respectively, for the nine months ended September 30, 2003.

The Company purchased gas from affiliates of Enron of approximately $4.7 million and $2.3 million, and from affiliates of El Paso of approximately $17.6 million and $21.1 million for the nine months ended September 30, 2004 and 2003, respectively. Transmission also purchased transportation services from Southern in connection with its Phase III Expansion completed in early 1995. Transmission contracted for firm capacity of 100,000 Mcf per day on Southern’s system for a primary term of 10 years, to be continued for successive terms of one year each year thereafter unless cancelled by either party, by giving 180 days notice to the other party prior to the end of the primary term or any yearly extension thereof. The amo unt expensed for these services totaled $4.9 million and $4.9 million for the nine months ended September 30, 2004 and 2003, respectively.

Effective the fourth quarter of 1997, the operation of the contracts held by Trading was divided between affiliates of Enron and El Paso. The fee charged, for services such as scheduling, billing, and other back office support, is based on a volumetric payment of $.005 per MMBtu, or approximately 50 percent of the prior arrangement.Trading accrued and paid $0.012 million and $.015 million to El Paso Merchant Energy for administrative fees for the nine months ended September 30, 2004 and 2003, respectively. Trading accrued $0.079 million, and paid $0.243 million (for all post-petition items) to ENA, for administ rative fees for the nine months ended September 30, 2003. Under this agreement, Trading was guaranteed an earnings stream based on all firm long-term contracts in place at November 1, 1997. The earnings stream thereafter fluctuated due to the variable pricing in effect, the result of ENA rejecting all aspects of certain agreements in bankruptcy proceedings. As of September 8, 2003, Trading assumed operating responsibility relating to securing all supply not provided by El Paso Merchant Energy and scheduling of volumes (see Note 3).

The Company either jointly owns or licenses with other Enron affiliates certain computer and telecommunications equipment and software that is critical to conducting its business. In other cases, such equipment or software is wholly owned by such affiliates, and the Company has no ownership interest or license in or to such equipment or software. Transmission participated in business applications that are shared among the Enron pipelines. All participating pipelines use the same common base system and also have a custom pipeline-specific component. Each pipeline pays for its custom development component and shares in the common base system development costs. There are specific software licenses that were entered into by an Enron affiliate that entitle Transmission to use the software licenses. Fees for this arr angement are included in the amounts paid for corporate administrative expenses.

Transmission is a party to a Participation Agreement, effective November 1, 2002, with Enron and Enron Net Works to provide Electronic Data Interchange (EDI) services through an outsourcing arrangement with EC Outlook. Enron renegotiated an existing agreement with EC Outlook that lowered the cost of EDI services and that also provided the means for Transmission to be compliant with the most recent North American Energy Standards Board (NAESB) EDI standards. The contract has a termination date of November 30, 2005. Fees for this arrangement are included in the amounts paid for corporate administrative expenses.

Transmission has a construction reimbursement agreement with ENA under which amounts owed to Transmission are delinquent. These obligations (including post-petition interest which generally cannot be collected in bankruptcy) total approximately $7.4 million and are included in Transmission’s filed bankruptcy claims. These receivables were fully reserved by Transmission prior to 2003. Transmission has also filed proofs of claims regarding other claims against ENA in the bankruptcy proceeding (see Note 9). In its rate case filed with the FERC (see Note 7), Transmission proposed to recover the estimated under-recovery on this reimbursement obligation by rolling the costs of the facilities constructed, less the estimated recovery from ENA, into its rates. Under the Settlement filed by Transmission on August 13 , 2004, Transmission will recover the difference (see Notes 7 and 9).

Transmission entered into a 20-year compression service agreement with Enron Compression Services Company (ECS) in March 2000. This agreement requires Transmission to pay ECS to provide electric horsepower capacity and related horsepower hours to be used to operate Compressor Station No. 13A, which consists of an electric compressor unit. Amounts paid to ECS under this agreement totaled $1.8 million and $1.7 million for the nine months ended September 30, 2004 and 2003. Under related agreements, ECS is required to pay Transmission an annual lease fee and monthly fees to operate and maintain the facilities. Amounts received from ECS during the nine months ended September 30, 2004 and 2003 for these services were $0.3 million and $0.3 million, respectively. A Netting Agreement, dated effective November 1, 2002, was executed with ECS, providing for the netting of payments due under each of the O&M, lease, and compression service agreements with ECS. Effective December 1, 2004, ECS assigned all of its interest in the compression services and related agreements to Paragon ECS Holdings, LLC, a non-affiliated entity.

(7) Regulatory Matters

Transmission’s currently effective rates were established pursuant to a Stipulation and Agreement (Rate Case Settlement) which resolved all issues in Transmission’s Natural Gas Act (NGA) Section 4 rate filing in FERC Docket No. RP96-366. The Rate Case Settlement, approved by FERC Order issued September 24, 1997, provided that Transmission could not file a general rate case to increase its base tariff rates prior to October 1, 2000 (except in certain limited circumstances), and was required to file no later than October 1, 2001 (since extended to October 1, 2003 pursuant to the Phase IV settlement discussed below). The Rate Case Settlement also provided that the rates charged pursuant to Transmission’s Firm Transportation Service (FTS) rate schedule FTS-2 would decrease effective March 1, 1999 and March 1, 2000.

On October 1, 2003, Transmission filed a general rate case, proposing rate increases for all services, based upon a cost of service of approximately $167.0 million for the pre-expansion system and approximately $342.0 million for the incremental system. Prospective changes proposed include the change to a traditional cost-of-service rate design (with straight-line depreciation, as opposed to variable depreciation under the currently-effective levelized rates) for the expansion system, a tracker for certain types of significant capital costs, and compliance with Order No. 637. A number of parties protested the rates. By order dated October 31, 2003, FERC suspended the proposed rates until April 1, 2004; set certain tariff revisions for a technical conference; set all other issues for hearing and accepted a tarif f change with regard to limiting reservation charge credits. Transmission made the required compliance filing and several customers protested, to which Transmission filed an answer in opposition. On April 20, 2004, FERC issued an order which accepted certain tariff changes and denied rehearing requests with regard to the reservation charge credits but required further changes. On May 20, 2004, Transmission sought rehearing of this order. On August 13, 2004, Transmission filed a Stipulation and Agreement of Settlement (Settlement), which resolves all issues set for hearing in Docket No. RP04-12, rehearing on the April 20 order, and all pending appeals of orders issued in Docket No. RP00-387. On December 21, 2004 FERC issued an order conditionally approving the Settlement and directing a further compliance filing to place new rates into effect, and to incorporate certain settlement provisions. No rehearing request was fi led; thus, the settlement will become effective on March 1, 2005.

On November 15, 2001, Transmission filed an NGA Section 7 certificate application with the FERC in Docket No. CP02-27-000 to construct 33 miles of pipeline and 18,600 horsepower of compression in order to expand the system to provide incremental firm service to several new and existing customers of 85,000 MMBtu on an average day (Phase VI Expansion). Expansion costs were estimated at $105.0 million. Transmission requested the expansion costs be rolled into rates applicable to FTS-2 (Incremental) service. The application was approved by FERC Order issued on June 13, 2002, and accepted by Transmission on July 19, 2002. Clarification was granted and a rehearing request of a landowner was denied by FERC Order of September 3, 2002. The Phase VI Expansion was completed and placed in service during 2003 with the excep tion of the compressor station modifications at stations 12, 15, and 24, which were completed and placed in-service on January 31, 2004, February 1, 2004 and April 3, 2004, respectively. Total costs through September 30, 2004 were $76.5 million.

In July 2002, the FERC issued a Notice of Inquiry (NOI) that seeks comments regarding its 1996 policy of permitting pipelines to enter into negotiated rate transactions. On July 25, 2003, the FERC issued its “Modification of Negotiated Rate Policy”, in which it determined that it “will no longer permit the use of gas basis differentials to price negotiated rate transactions.” On August 25, 2003, the Interstate Natural Gas Association of America (INGAA) filed a request for rehearing of this ruling. On September 12, 2003, the Commission issued an order granting rehearing for the purposes of further consideration, thus, tolling the statutory time in which the FERC is required to act. On December 18, 2003, the Commission issued orders in two cases, essentially reversing this ruling for rates tha t will remain between the minimum and maximum tariff rates. Transmission has only two negotiated rate agreements, and both of these are at or below Transmission’s currently effective maximum tariff rates as well as the proposed rates in the 2003 rate case (see note on rate case above). Thus, Transmission does not anticipate its negotiated rate transactions being impacted by this rulemaking. At this time, Transmission cannot predict the outcome of this NOI.

In 2002, Transmission was subject to an industry-wide nonpublic investigation of the FERC Form 2 (FERC’s annual report) focusing on cash management or transfers between Transmission and Enron or affiliated companies. By order issued September 8, 2003, the FERC determined that Transmission was generally in compliance. However, the FERC found that because Transmission was in a cash management pool during the time of the audit and because best management practices require a written cash management plan, Transmission should have a written cash management plan. On October 8, 2003, Transmission sought clarification or, in the alternative, rehearing of the order that Transmission did not have to have a written cash management plan at this time because Transmission was not now participating in a cash management po ol. On December 4, 2003, the FERC issued an order granting Transmission’s request for clarification.

On November 25, 2003, the FERC issued Order No. 2004 making significant changes in the Standards of Conduct (“SOC”) governing the relationships between pipelines and Energy Affiliates. The new SOC applies to a greater number of affiliates, requires more reporting, and requires appointment of a compliance officer. On December 24, 2003, INGAA filed a request for rehearing. On January 20, 2004, the Commission issued an order granting rehearing for the purposes of further consideration, thus tolling the statutory time in which the FERC is required to act. At this time, Transmission cannot predict the final outcome of the proceeding. On February 9, 2004, Transmission made the required informational filing with regard to compliance by June 1. Certain companies plan to seek delay of the implementation to September 2004, in view of the number of pending rehearing and clarification requests. The FERC granted rehearing in part, and Transmission has fully complied with all training, posting and other requirements of the order.

On December 15, 2003, the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulation defines as “high consequence areas” (HCA). This rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002, a bill signed into law on December 17, 2002. The rule requires operators to identify HCAs along their pipelines by December 2004, to have begun baseline integrity assessments, comprised of in-line inspection (smart pigging), hydrostatic testing, or direct assessment, by June 2004. Operators must risk rank their pipeline segments containing HCAs, and have the highest 50 percent assessed using one or more of these methods by December 2007. The balance must be completed by December 2012. The costs of utilizing these methods typically range from a few thousand dollars per mile to well over $15,000 per mile. In addition, some system modifications will be necessary to accommodate the inspections. Because identification and location of all the HCAs has not been completed, and because it is impossible to determine the scope of required remediation activities prior to completion of the assessments and inspections, the cost of implementing the requirements of this regulation is impossible to determine at this time. The required modifications and inspections are estimated to range from approximately $12.0 - $15.0 million per year, with remediation costs in addition to these amounts. A provision in the Settlement described above provides for recovery of some added assessment and repair/replacement capital costs via a special capital surcharge, if certain conditions are met.

On February 6, 2004, Enron filed two form U1’s with the Securities and Exchange Commission (SEC) proposing a set of conditions under which Enron would register as a holding company under PUHCA. Among other things, Enron sought an exemption for the Company under Rule 16 of the SEC’s PUHCA Rules and Regulations (17 CFR§ 250.16, “Exemption of Non-Utility Subsidiaries and Affiliates”) (The Exemption). On March 9, 2004, Enron amended its form U1 application filings, withdrew its application for exemption filed on December 31, 2003, and filed a form U5A, registering as a public utility holding company under PUHCA. Also on March 9, 2004, the SEC issued orders approving the applications made on the amended form U1’s and the U5A, including approval of the application for the Exemption. The result of these proceedings has reconfirmed the Company’s exemption.

(8) Property, Plant and Equipment

The principal components of the Company's Property, Plant and Equipment are as follows (in thousands):

	September 30, 2004			December 31, 2003
Transmission Plant	$	2,778,907		$	2,725,065
General Plant		24,531			25,619
Intangible Plant		23,739			20,612
Construction Work-in-progress		5,645			35,638
Acquisition Adjustment		1,252,466			1,252,466
		4,085,288			4,059,400
Less: Accumulated depreciation and amortization		(1,117,318	)		(1,072,072	)
Net Property, Plant and Equipment	$	2,967,970		$	2,987,328

Intangible assets from above includes the following (in thousands):

	September 30, 2004			December 31, 2003			Weighted average amortization period (in years)
Intangible Assets:
Software licenses	$	22,239		$	19,112			4
Contribution in aid of construction		1,500			1,500			6
Intangible Assets, at Cost		23,739			20,612
Less - Accumulated depreciation and amortization		(15,595	)		(13,012	)
Intangible Assets - Net	$	8,144		$	7,600

Amortization of intangible assets over the next five years is estimated to be recognized as follows (in thousands):

Fiscal year:	Amount
2004 (remaining 3 months)		434
2005		1,782
2006		1,546
2007		1,296
2008		1,084

(9) Commitments and Contingencies

In the normal course of business, the Company is involved in litigation, claims or assessments that may result in future economic detriment. The Company evaluates each of these matters and determines if loss accruals are necessary as required by SFAS No. 5, “Accounting for Contingencies.” The Company does not expect to experience losses that would be materially in excess of the amount accrued at September 30, 2004.

Transmission and Trading have filed bankruptcy related claims against Enron and other affiliated bankrupt companies totaling $220.6 million. Transmission’s claims include rejection damages and delinquent amounts owed under certain transportation agreements, an unpaid promissory note, and other fees for services and imbalances. Subsequent to Transmission’s filing its claims, ENA’s firm transportation agreements were permanently relinquished to a creditworthy party, which significantly reduced Transmission’s rejection damages (see Note 6). Trading’s claim is for rejection damages on two physical/financial swaps and a gas sales contract, as well as certain delinquent amounts owed pre-petition. Transmission and Enron resolved all claims except for the deferred compensation claim, for which settlement documents are being drafted (see Note 4).

On March 7, 2003, Trading filed a declaratory order action, involving a contract between it and Duke. Trading requested that the court declare that Duke was required to furnish certain “optional volumes” and that Duke has not suffered a “loss of supply” under the parties’ contract, which could, if it continued, have given rise to the right of Duke to terminate the contract at a point in the future. On April 14, 2003, Duke sent Trading a notice that the contract was terminated as of April 16, 2003 (due to Trading’s alleged failure to timely increase the amount of a letter of credit); although it disagreed with Duke’s position, Trading increased the letter of credit on April 15. Duke has answered and filed a counterclaim, arguing that Trading failed to timely increase the amount of a letter of credit, and that it has breached a “resale restriction” on the gas. Trading disputes that it has breached the agreement, or that any event has given rise to a right to terminate by Duke. On May 1, 2003, Trading notified Duke that it was in default under the Agreement, for failure to deliver the base volumes beginning April 17, 2003. However, Duke continued to refuse to perform under the contract. On June 2, 2003, Trading notified Duke that, because Duke had not cured its default, Trading terminated the agreement effective as of June 5, 2003. On August 8, 2003, Trading sent its final “termination payment” invoice to Duke in the amount of $187.0 million. On October 6, 2003, Trading filed its Amended Petition, alleging wrongful termination and containing the termination damages. On November 25, 2003, Trading filed its Second Amended Complaint, alleging, among other things, that Duke was required to give reasonable notice to Trading to upgrade the letter of credit, before term inating the contract. On December 5, 2003, Duke filed its answer. On March 23, 2004, Trading filed a motion for Summary Judgment against Duke, seeking a ruling that Duke was required to provide Trading with notice before terminating the agreements. On July 28, 2004 Trading filed its amended Motion for Partial Summary Judgment; Duke’s response and Cross Motion for Partial Summary Judgment was filed on August 19, 2004. Trading’s reply to Duke’s cross motion was filed September 3, 2004 to which Duke replied on September 17, 2004 to which Trading replied on September 29, 2004. These motions are pending before the judge; no oral argument has been scheduled. This is a disputed matter, and there can be no assurance as to what amounts, if any, Trading will ultimately recover. Management believes that the amount ultimately recovered will not be materially different than the amount recognized through September 30, 2004, and that the ultimate resolution of this matter will not have a materially adverse e ffect on the Company’s consolidated financial position, results of operations or cash flows. Management further believes that claims made by Duke against the Company with regard to this matter are without merit and do not constitute a liability which would require adjustment to or disclosure in the Company’s September 30, 2004, consolidated financial statements as management has deemed the likelihood of an adverse outcome to be remote.

In 1999, Transmission entered into an agreement which obligated it to various natural gas and construction projects includable in its rate base. At December 31, 2003, Transmission expected to incur an additional $1.1 million of potentially capitalizable costs prior to contract expiration; however, this obligation was terminated during the nine months ended September 30, 2004.

The Florida Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various turnpike widening projects in the planning stages, which may, over the next ten years, impact one or more of Transmission’s mainline pipelines that are co-located in FDOT/FTE rights-of-way. Transmission is currently aware of seven projects with a total of approximately 35 miles that are scheduled for construction between 2005 and 2008 that could potentially impact Transmission’s mainlines along the Beeline Expressway and the Sunshine State Parkway. The FDOT/FTE and Transmission are currently in discussions with respect to widening projects covering approximately 13 miles that are currently scheduled for construction during 2005 and which will impact Transmission’s 18” and 24” pipelines in Broward County. Two other FDOT/FTE projects, covering approximately 8.1 miles in Broward County and scheduled for construction during 2006 or 2007 will also impact Transmission’s 18” and 24” pipelines. An additional FDOT/FTE project to install a new toll plaza in Broward County is scheduled for 2008 construction. The FDOT/FTE has informed Transmission that the plan is to complete the widening projects through Broward County and later, also through Palm Beach County, by 2010.

Under certain conditions, the existing agreements between Transmission and the FDOT/FTE require the FDOT/FTE to provide any new right-of-way needed for relocation of the pipelines and for Transmission to pay for rearrangement or relocation costs. Under certain other conditions, Transmission may be entitled to reimbursement for the costs associated with relocation, including construction and right of way costs. Transmission has presented the FDOT/FTE with an invoice for reimbursement of the costs incurred by Transmission in connection with a previous relocation project, and the FDOT/FTE has denied liability for such costs under the provisions of the existing easements. The total miles of pipe to be impacted ultimately for all of the FDOT/FTE widening projects, and the associated relocation and/or right-of-way co sts, cannot be determined at this time.

(10) Comprehensive Income

Comprehensive income includes the following (in thousands):

	Nine Months Ended
	September 30, 2004		September 30, 2003
Net income	$	92,990	$	58,096
Other comprehensive income:
Derivative instruments - Recognition in earnings of previously deferred (gains) and losses related to derivative instruments used as cash flow hedges		906		905
Total comprehensive income	$	93,896	$	59,001

(11) Subsequent Events

Pursuant to its Plan of Reorganization filed with the U.S Bankruptcy Court, Enron formed CrossCountry and contributed its interest in the Company to CrossCountry Citrus, LLC, effective March 31, 2004. Effective November 17, 2004, CrossCountry became a wholly owned subsidiary of CCE Holdings, LLC, which is a joint venture currently owned by subsidiaries of Southern Union (50 percent), GE (30 percent) and four minority interest owners (20 percent in the aggregate). All of the voting interests of CCE Holdings are owned by Southern Union and GE. At or around the time of the acquisition, certain of the entities were converted to limited liability companies. On November 17, 2004, Transmission drew $135.0 million on the 2004 Revolver, allowing the Company to pay a dividend of $140.0 million to its equity owners.

EX-99.F

EXHIBIT 99.f

SOUTHERN UNION COMPANY AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

The following unaudited pro forma consolidated condensed financial statements present the consolidated financial data of Southern Union Company and its subsidiaries, after giving effect to Southern Union's capital contribution to CCE Holdings (its joint venture with GE) and CCE Holdings’ concurrent acquisition of CrossCountry on November 17, 2004. CCE Holdings’ aggregate purchase price for the CrossCountry Acquisition was approximately $2,450 million including assumed debt of approximately $352 million.

At the time of the CrossCountry Acquisition, CCE Holdings owned interests in three North American natural gas pipeline businesses, including TWP, Citrus Corp. and Northern Plains, in which CrossCountry indirectly held 100%, 50% and 100% interests, respectively. CrossCountry also owned a 100% interest in Services, which is the management company that employs certain of the personnel that manage CrossCountry’s pipeline interests. Pursuant to an agreement with ONEOK and concurrent with the CrossCountry Acquisition, CCE Holdings sold its interest in Northern Plains for $175 million. Because Northern Plains is no longer a part of CrossCountry, the historical results of Northern Plains have been excluded from the unaudited pro forma consolidated condensed financial statements as its historical results are not mat erial to an understanding of the future operations of CCE Holdings and Southern Union. The allocation of the purchase price to CrossCountry’s interest in Northern Plains was equivalent to the sales proceeds of $175 million. Accordingly, no gain or loss was recognized on the sale. Additionally, substantially all of the expenses of Services were billed to, and on behalf of, TWP, Citrus Corp. and Northern Plains, and Services had no material revenues other than billings at cost to CrossCountry’s pipeline businesses. Accordingly, the net results of Services are embedded in the stand-alone results of TWP, Citrus Corp. and Northern Plains and are not presented separately. Furthermore, because certain CrossCountry employees have been terminated in connection with the sale of Northern Plains, the costs incurred by Services attributable to Northern Plains are not expected to be incurred by CCE Holdings in the future. Based on the foregoing, the unaudited pro forma consolidated condensed financial statements include only the historical results of TWP and CrossCountry’s interest in Citrus Corp.

Southern Union funded its $590.5 million equity investment in CCE Holdings in November 2004 through borrowings of $407 million under a bridge loan facility, net proceeds of $142 million from the settlement on November 16, 2004 of its July 2004 forward sale of 8,242,500 shares of its common stock and additional borrowings of approximately $42 million under Southern Union’s existing revolving credit facility. CCE Holdings funded the $2,450 million CrossCountry Acquisition through (i) proceeds of $590.5 million from the equity contributions of each of Southern Union and GE, (ii) proceeds from the issuances of indebtedness of $1,055 million at subsidiaries of CrossCountry, (iii) proceeds of $175 million from the sale of Northern Plains and (iv) approximately $39 million from cash acquired. CCE Holdings’ is suances of indebtedness were made through four different debt facilities at TW Holdings and TWP, subsidiaries of CCE Holdings. The primary source of the cash acquired which was used to partially fund the acquisition was a $70 million dividend paid by Citrus Corp. to CCE Holdings on the acquisition date, less certain costs, including $24 million related to the acquisition debt incurred by TW Holdings and TWP. The unaudited pro forma consolidated condensed financial statements give effect to each of the aforementioned financing transactions. The balance of the bridge loan will likely be repaid from a future capital market transaction. No such future capital market transaction has been reflected in the accompanying unaudited pro forma consolidated condensed financial statements.

The unaudited pro forma consolidated condensed balance sheet as of September 30, 2004 gives effect to the CCE Acquisition as if it occurred on that date. The unaudited pro forma consolidated condensed statements of operations for the year ended June 30, 2004, and the three months ended September 30, 2004, give effect to the CCE Acquisition as if it had occurred on July 1, 2003.

Although Southern Union has recently announced its decision to change its fiscal year to December 31, the historical fiscal year end of Southern Union has been June 30. TWP and Citrus Corp. have a fiscal year end of December 31. The unaudited pro forma consolidated condensed statements of operations for the year ended June 30, 2004, and the three months ended September 30, 2004, have been prepared using comparable financial statement periods of Southern Union, TWP and Citrus Corp. Southern Union's historical statement of operations for the year ended June 30, 2004 is derived from its audited consolidated financial statements. Southern Union’s historical statement of operations for the three months ended September 30, 2004 is derived from its unaudited consolidated financial statements. The compiled financia l results of TWP and Citrus Corp. for the twelve months ended June 30, 2004 were calculated by subtracting the six-month period ended June 30, 2003 from the year ended December 31, 2003 and adding the result to the six-month period ended June 30, 2004, and are unaudited. The historical financial results of TWP and Citrus Corp. for the three months ended September 30, 2004 are derived from their unaudited financial statements. The following unaudited pro forma consolidated condensed financial statements have been prepared from, and should be read in conjunction with, these historical financial statements and related notes thereto.

The excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed of CrossCountry is reflected in the pro forma adjustments as unamortizable goodwill. Management's preliminary purchase price allocation assumes that the book value of its property, plant and equipment is equal to its fair value for both TWP and Citrus Corp. Management’s preliminary purchase price allocation also assumes that the value attributed to identifiable intangible assets, including capitalized software and customer contracts, is approximately $20 million for TWP and $40 million for Citrus Corp. ($20 million attributable to CCE Holdings' interest). Therefore, the unaudited pro forma consolidated condensed financial statements assume that the entire difference between the purchase price and th e book value of the net assets of TWP and CCE Holdings' investment in Citrus Corp. is attributable to intangible assets. The estimate of the fair value of the assets and liabilities is preliminary and will be revised to reflect the results of independent appraisals, which have not been completed.

The following unaudited pro forma consolidated condensed financial statements are presented in accordance with the assumptions set forth below for purposes of illustration only and are not necessarily indicative of the financial position or operating results that would have occurred if the CrossCountry Acquisition and related financing transactions had been consummated on the date as of which, or at the beginning of the period for which, they are being given effect, nor are they necessarily indicative of the future operating results or financial position of the consolidated enterprise. The unaudited pro forma consolidated condensed financial statements do not contain any adjustments to reflect cost savings or other synergies anticipated as a result of the acquisition. Operating results for the three months ended September 30, 2004 are not indicative of the results that may be expected for the six-month period ending December 31, 2004. All dollar amounts included in the notes to the unaudited consolidated condensed financial statements, and the tables therein, are in thousands, unless otherwise indicated.

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

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

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

SOUTHERN UNION COMPANY AND SUBSIDIARIES

NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Adjustments to the Unaudited Pro Forma Consolidated Condensed Balance Sheet

(A)   Reflects the proceeds from borrowings and the settlement of the forward sale of common shares, the purpose of which was to fund Southern Union's capital contribution to CCE Holdings, as follows:

The bridge loan facility has a six-month term and bears an interest rate of LIBOR + 1.25%. The settlement of the forward equity sale of common shares occurred on November 16, 2004 and resulted in the issuance of 8,242,500 common shares.

(B)   Reflects Southern Union's initial capital contribution to CCE Holdings in exchange for its 50% interest. Southern Union accounts for its investment in CCE Holdings under the equity method.

(C)   Reflects acquisition costs incurred by Southern Union. These costs include investment banking, legal, accounting and consulting costs that were directly attributable to Southern Union's investment in CCE Holdings. Approximately $5.9 million of these costs were incurred prior to September 30, 2004, and were reflected in other assets in the balance sheet as of September 30, 2004. Upon consummation of the acquisition on November 17, 2004, all direct acquisition costs (totaling $15 million) were reclassified to investments in affiliates.

Adjustments to the Unaudited Pro Forma Consolidated Condensed Statements of Operations

(D)   Reflects Southern Union's equity in the earnings of CCE Holdings before consideration of adjustments to reflect the impact of preliminary purchase price allocations and the impact of additional debt at CCE Holdings. As discussed in the introduction to these unaudited pro forma consolidated condensed financial statements, this adjustment only reflects the stand-alone operations of TWP and Citrus Corp., rather than the combined operations of CrossCountry. The basis for this presentation is supported by: (i) CrossCountry's interest in Northern Plains was sold for $175 million to ONEOK, Inc. concurrent with CCE Holdings' acquisition of CrossCountry, and therefore, is not relevant to the continuing impact of CCE Holdings on Southern Union, (ii) Services' ongoing operations are primari ly for the benefit of TWP and Citrus Corp., and therefore, its expenses are embedded in the stand-alone financial statements of TWP and Citrus Corp., (iii) there were no intercompany transactions between TWP and Citrus Corp. for the periods presented and (iv) there were no operations at any of the intermediate holding companies (i.e., TW Holdings and CrossCountry Citrus). The calculation of the adjustment to equity in earnings is as follows:

In connection with CCE Holdings' acquisition of CrossCountry, TWP and its parent, TW Holdings, were converted on or about November 17, 2004, from C corporations to limited liability companies (LLCs). Because CCE Holdings, TW Holdings and TWP are LLCs, their earnings are taxed only at their owners. Accordingly, Southern Union's equity in the earnings of TWP is presented based on income before income taxes rather than net income (i.e., income taxes of $25,292 reported in TWP's statement of operations for the year ended December 31, 2003 have been excluded from the earnings above). Conversely, because Citrus is a C corporation, Southern Union's equity in the earnings of Citrus is recorded based on net income. Included in net income for the twelve months ended June 30, 2004, was net income related to Citrus Corp.'s natural gas trading operation of approximately $12.1 million. Citrus Corp. began exiting the natural gas trading business in 1997 and completed the sale of its last remaining gas trading contract in the fourth calendar quarter of 2004.

(E)   Reflects the impact on Southern Union's equity in earnings from CCE Holdings resulting from the increase in amortization expense attributable to the allocation of the estimated excess of the purchase price over the book value of certain identifiable intangible assets. Management's preliminary purchase price allocation assumes that the book value of its property, plant and equipment is equal to its fair value for both TWP and Citrus Corp. Management's preliminary purchase price allocation assumes that the value attributed to identifiable intangible assets, including capitalized software and customer contracts, is approximately $20 million for TWP and $40 million for Citrus Corp. ($20 million attributable to CCE Holdings' interest). Therefore, the unaudited pro forma consolidat ed condensed financial statements assume that the entire difference between the purchase price and the book value of the net assets of TWP and CCE Holdings' investment in Citrus Corp. is expected to be attributable to intangible assets, including goodwill. These assets, except for goodwill, are assumed to have useful lives and amortization periods of five years. Accordingly, the estimated impact on Southern Union's financial statements attributable to this additional amortization is $4 million per year. For every change of $10 million in value attributed to identifiable intangible assets with amortization periods of five years, amortization expense would change by $2 million per year, $1 million of which will be attributable to Southern Union's interest. The remainder of the excess purchase price is expected to be attributable to unamortizable goodwill. The portion of that goodwill attributable to TWP is recorded on CCE Holdings' consolidated balance sheet and the remainder is recorded within CCE Holdin gs' investment in Citrus Corp. The estimate of the fair value of the net assets is preliminary and will be revised to reflect the results of independent appraisals, which have not been completed.

The total amount of the preliminary purchase price attributed to goodwill is approximately $469 million, $173 million of which is attributable to TWP and $296 million of which is attributable to Citrus Corp. (and is recorded in CCE Holdings' investment in affiliates account). The table below illustrates the decrease in annual earnings before taxes and basic earnings per share that would occur if a portion of the amount attributed to goodwill in the preliminary purchase price allocation were subsequently deemed to be attributable to depreciable property, plant and equipment in connection with the finalization of independent appraisals. The calculations below assume a composite depreciation rate of 2.50 percent per year (40 year assumed average remaining life) for both TWP and Citrus Corp. (per share amounts n ot in thousands of dollars).

(F)   Reflects the impact on Southern Union's equity in earnings resulting from additional interest expense on acquisition debt incurred at TW Holdings and TWP. There are five different debt instruments: a $130 million revolver at TWP ($0 drawn), a $100 million term loan at TWP, a $230 million term loan at TW Holdings, $520 million of private notes ($500 million issued) at TWP and $225 million of private notes ($225 million issued) at TW Holdings. TWP and TW Holdings also incurred approximately $24 million in costs associated with these debt instruments. Those costs have been capitalized and will be amortized as an adjustment to interest expense over the term of the related instruments. The following calculations use spreads outlined in the various facility agreements over the one-m onth USD LIBOR quote as of January 26, 2005. The acquisition debt was used in part to repay existing debt at TWP. Therefore, the net adjustment reflects a reduction for the historical interest on that debt. For every 1/8 percentage change in the interest rate assumed for the floating rate debt (term loans only), interest expense for the year ended June 30, 2004 would change by approximately $413,000.

In connection with these borrowings, TWP incurred approximately $11 million and TW Holdings incurred approximately $13 million of direct costs. Those costs were capitalized and will be amortized as an adjustment to interest expense over the term of the various debt instruments. The following calculations assume these costs are allocated on a pro rata basis between the term loans and revolver (five-year term) and the notes (ten-year and twelve-year terms) as follows:

(G)   Reflects interest expense related to Southern Union's bridge loan facility of $590.5 million ($407 million drawn) and $41.5 million of additional borrowings under Southern Union's revolving credit facility. The interest rates used in the following calculation are based on spreads outlined in the relevant debt agreements over the one-month USD LIBOR quote as of January 26, 2005. For every 1/8 percent change in the interest rate assumed for these borrowings, interest expense for the year ended June 30, 2004 would change by approximately $561,000.

(H)   Reflects the income tax consequences of the pro forma adjustments at Southern Union's statutory federal tax rate of 35%. Because generally accepted accounting principles require that equity in earnings of unconsolidated investees be taxed at the investor's effective tax rate, the equity in earnings from Citrus Corp. is also taxed at the Southern Union effective rate. However, Southern Union may qualify for a dividends received deduction when Citrus Corp. actually pays a dividend. Such a dividends received deduction would lower the actual cash tax burden attributable to the Citrus Corp. earnings.

(I)   Reflects Southern Union's equity in the earnings of CCE Holdings before consideration of adjustments to reflect the impact of preliminary purchase price allocations and the impact of additional debt at CCE Holdings.

(J)   Reflects the impact on Southern Union's equity in earnings resulting from additional interest expense on acquisition debt incurred at TW Holdings and TWP. The following calculations use spreads outlined in the various facility agreements over the one-month USD LIBOR quote as of January 26, 2005. For every 1/8 percentage change in the interest rate assumed for the floating rate debt (term loans only), interest expense for the three months ended September 30, 2004 would change by approximately $104,000.

In connection with these borrowings, TWP and TW Holdings incurred certain direct costs, as described in Note (F) above.

The impact of the amortization of these debt issue costs on interest expense is as follows:

(K)   Reflects interest expense related to Southern Union's bridge loan facility of $590.5 million ($407 million drawn) and $41.5 million of additional borrowings under Southern Union's revolving credit facility. The interest rates used in the following calculation are based on spreads outlined in the relevant debt agreements over the one-month USD LIBOR quote as of January 26, 2005. For every 1/8 percent change in the interest rate assumed for these borrowings, interest expense for the three months ended September 30, 2004 would change by approximately $141,000.