Southern Union Company 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

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

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

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

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

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)(see 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 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 conjunction with the Company’s audited consolidated financial statements and the notes thereto for the year ended December 31, 2003.

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 effective 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.

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).

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 price 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 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 in Other Deferred Charges of $66.9 million and $72.5 million at September 30, 2004 and December 31, 2003, respectively (see Note 9).

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 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 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.

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 that 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.

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 materially 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.

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 amount 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 administrative 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 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.

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 tariff 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 filed; 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 exception 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 that 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 pool. 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.

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 terminating 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 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 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.

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 costs, cannot be determined at this time.

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.

	Nine Months Ended
Customers	September 30, 2004		September 30, 2003

Florida Power & Light Company	$	142.1	$	139.4

	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

	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

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

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