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 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.

        /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 to 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 Transmission 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 the 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 change 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 significant 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 the 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 restatement 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, Enron 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 recognized 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 ultimate 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 estimates 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 Expansion 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 contracts 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 majeure 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 withdrawal 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 exception 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 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.

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 balance 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 proprietary 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 allows 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 discuss 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 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 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 remanded 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, 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. 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, due 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 sought 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. 143 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 initiated 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 proceedings 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.