Entergy – Koch, LP

	December 31,
	2003	2002
	(In Thousands)

Assets
Current assets:
Cash and cash equivalents	$ 277,964	$ 115,960
Margin and collateral deposits	186,624	163,848
Accounts receivable:
Trade (less allowance of $13,137 and $11,955, respectively)	859,328	769,285
Affiliates	37,305	30,067
Contribution receivable	–	32,831
Transportation and exchange receivables	44,170	26,699
Receivable from Partners	6,755	7,646
Natural gas inventory	249,332	396,992
Assets from trading activities	680,643	571,172
Other current assets	195,701	196,716
Total current assets	2,537,822	2,311,216

Noncurrent assets:
Property, plant, and equipment, net	947,839	908,259
Assets from trading activities	192,316	183,506
Other noncurrent assets	39,665	33,234
Total noncurrent assets	1,179,820	1,124,999



Total assets	$ 3,717,642	$ 3,436,215

	December 31,
	2003	2002
	(In Thousands)

Liabilities and partners’ capital
Current liabilities:
Accounts payable:
Trade	$ 821,735	$ 693,055
Affiliates	7,478	31,778
Transportation and exchange payables	28,277	15,917
Collateral held on deposit	114,347	167,975
Liabilities from trading activities	574,870	519,922
Accrued liabilities	135,576	87,399
Notes payable – credit facilities	32,337	248,000
Other current liabilities	8,532	2,965
Total current liabilities	1,723,152	1,767,011

Noncurrent liabilities:
Senior notes (net of discount)	501,721	299,222
Liabilities from trading activities	291,542	143,843
Other noncurrent liabilities	17,981	16,974
Total noncurrent liabilities	811,244	460,039

Commitments and contingencies

Partners’ capital:
General Partner (including accumulated other comprehensive (loss) income of $(21) and $40, respectively)	11,832	12,092
Limited Partners (including accumulated other comprehensive (loss) income of $(2,030) and $3,938, respectively)	1,171,414	1,197,073
Total partners’ capital	1,183,246	1,209,165
Total liabilities and partners’ capital	$ 3,717,642	$ 3,436,215

See accompanying notes.

Entergy - Koch, LP

Consolidated Statements of Income

	Year Ended December 31,		Eleven Months Ended December 31,
	2003	2002	2001
	(In Thousands)

Natural gas pipeline:
Revenues:
Transportation and storage – trade	$ 110,079	$ 120,476	$ 105,299
Transportation and storage – affiliates	12,370	6,368	3,170
Retained fuel and other	54,352	34,240	52,631
Total natural gas pipeline revenues	176,801	161,084	161,100

Costs:
Operations and maintenance	116,923	69,857	65,609
Taxes other than income	6,625	5,854	5,684
Total natural gas pipeline costs	123,548	75,711	71,293

Trading:
Net gain from trading activities	339,362	259,472	257,747
Gross profit	392,615	344,845	347,554

Depreciation and amortization	42,851	42,087	35,281
General and administrative	156,932	147,529	104,675
Operating income	192,832	155,229	207,598

Other income and expense:
Interest income	6,020	1,728	2,868
Interest expense	(28,527)	(22,238)	(20,828)
Other (expense) income	(966)	18,225	(2,717)
Total other expense	(23,473)	(2,285)	(20,677)
Income before income tax expense and cumulative effect of changes in accounting principle	169,359	152,944	186,921

Income tax expense	4,494	3,684	3,510
Income before cumulative effect of changes in accounting principle	164,865	149,260	183,411

Cumulative effect of changes in accounting principle (net of tax benefit of $4,477 in 2003)	15,245	–	(11,330)
Net income	$ 180,110	$ 149,260	$ 172,081

See accompanying notes.

Entergy - Koch, LP

Consolidated Statements of Changes in Partners' Capital

	General Partner	Limited Partners	Total
	(In Thousands)


Balance at February 1, 2001 (Inception)	$ 8,510	$ 842,505	$ 851,015
Net income	1,721	170,360	172,081
Other comprehensive income:
Foreign currency translation	3	332	335
Net cash flow hedge gain	56	5,558	5,614
Net cash flow hedge gain recognized in net income	(42)	(4,146)	(4,188)
Total other comprehensive income	17	1,744	1,761
Total comprehensive income	1,738	172,104	173,842
Balance at December 31, 2001	10,248	1,014,609	1,024,857
Capital contribution	328	32,503	32,831
Net income	1,493	147,767	149,260
Other comprehensive income:
Foreign currency translation	37	3,606	3,643
Net cash flow hedge gain	26	2,543	2,569
Net cash flow hedge gain recognized in net income	(40)	(3,955)	(3,995)
Total other comprehensive income	23	2,194	2,217
Total comprehensive income	1,516	149,961	151,477
Balance at December 31, 2002	12,092	1,197,073	1,209,165
Capital distributions	(2,000)	(198,000)	(200,000)
Net income	1,801	178,309	180,110
Other comprehensive income:
Foreign currency translation	69	6,824	6,893
Net cash flow hedge loss	(133)	(13,114)	(13,247)
Net cash flow hedge loss recognized in net income	3	322	325
Total other comprehensive loss	(61)	(5,968)	(6,029)
Total comprehensive income	1,740	172,341	174,081
Balance at December 31, 2003	$ 11,832	$ 1,171,414	$ 1,183,246

See accompanying notes.

Entergy - Koch, LP

Consolidated Statements of Cash Flows

	Year Ended December 31,		Eleven Months Ended December 31,
	2003	2002	2001
	(In Thousands)

Cash flows from operating activities
Net income	$ 180,110	$ 149,260	$ 172,081
Adjustments to reconcile net income to net cash flows provided by (used in) operating activities:
Provision for loss on accounts receivable	1,182	11,507	448
Depreciation and amortization	42,851	42,087	35,281
Cumulative effect of change in accounting principle	(15,245)	–	11,330
Change in net assets from trading activities	87,801	15,844	(49,534)
Gain on sale of asset	–	(775)	–
Net changes in working capital	132,656	(373,657)	143,304
Change in net other noncurrent assets and liabilities	1,273	13,426	(21,706)
Net cash flows provided by (used in) operating activities	430,628	(142,308)	291,204

Cash flows from investing activities
Capital expenditures	(88,277)	(50,133)	(26,869)
Proceeds from sale of asset	–	9,897	–
Net cash flows used in investing activities	(88,277)	(40,236)	(26,869)

Cash flows from financing activities
Net (repayment) borrowing of credit facility notes payable	(215,663)	88,000	(305,751)
Repayment of notes payable to partners	–	–	(212,000)
Capital contribution	32,831	–	–
Proceeds from senior notes borrowing	199,910	–	299,094
Capital distributions	(200,000)	–	–
Net cash flows (used in) provided by financing activities	(182,922)	88,000	(218,657)

Effect of exchange rate changes on cash and cash equivalents	2,575	3,486	484

Net change in cash and cash equivalents	162,004	(91,058)	46,162
Cash and cash equivalents, beginning of period	115,960	207,018	160,856
Cash and cash equivalents, end of period	$ 277,964	$ 115,960	$ 207,018

Cash paid for taxes (in millions)	$ 6.9	$ 6.4	$ 1.6
Cash paid for interest (in millions)	$ 27.8	$ 25.9	$ 17.7

See accompanying notes.

Entergy - Koch, LP

Notes to Consolidated Financial Statements

December 31, 2003

1. Organization and Nature of Operations

Entergy – Koch, LP (“EKLP” or the “Partnership”), is a limited partnership indirectly owned by subsidiaries of Entergy Corporation (“Entergy”) and Koch Industries, Inc. (“Koch”) (collectively, the “Partners”). Subsidiaries of Entergy and Koch own 99% of the Partnership through limited partner interests, and the remaining 1% of the Partnership is owned by the general partner, EKLP, LLC, a company owned 50% by EK Holding III, LLC (an Entergy subsidiary), and 50% by Koch Energy, Inc. (a Koch subsidiary). EKLP, LLC, is managed by a board of directors, with each partner having equal representation.

Pursuant to the Agreement of Limited Partnership, dated January 31, 2001 (the “Partnership Agreement”), general distributions are equally shared by the Partners; however, the Partners disproportionately share in certain profits and special allocations, which occur periodically and would occur upon liquidation. The Partnership Agreement also requires that distributions of cash be made quarterly, based on EKLP, LLC’s determination of excess cash, which determination is based on EKLP management’s recommendation.

EKLP was formed to combine certain natural gas and power trading contracts and assets of Entergy with the natural gas pipeline business and the natural gas, power, and weather trading business of Koch. The accompanying consolidated financial statements reflect the transactions of the Partnership subsequent to its inception. The Partnership operates these contributed businesses, contracts, and assets primarily through four wholly owned subsidiaries: Gulf South Pipeline Company, LP (“Gulf South”), Entergy – Koch Trading, LP (“EKT US”), Entergy – Koch Trading Canada, ULC (“EKT CAN”), and Entergy – Koch Trading, Ltd. (“EKT Europe”).

Gulf South is engaged in the gathering, transmission, and storage of natural gas in the Gulf Coast region of the United States. Gulf South’s operations are collectively referred to as “pipeline services” in these notes and comprise one of the two reportable segments of the Partnership.

EKT US engages in physical and financial natural gas trading, including asset optimization services and weather derivatives trading in the United States and Canada, as well as physical and financial power trading throughout the United States. EKT CAN, which began operations in December 2002, engages in physical and financial natural gas trading, including asset optimization services, in Canada. EKT Europe engages in physical and financial natural gas and power trading as well as weather derivatives trading in the United Kingdom and Western Europe. The EKT US, EKT Europe, and EKT CAN operations are collectively referred to as “EKT” or “trading services” in these notes and comprise one of the two reportable business segments of the Partnership.

2. Significant Accounting Policies

Principles of Consolidation – The consolidated financial statements include the accounts of all of the Partnership’s wholly owned subsidiaries after the elimination of significant intercompany transactions and balances. Investments in entities that are not controlled by the Partnership are accounted for using either the cost or equity method, as appropriate. These investments are regularly reviewed for impairment and propriety of current accounting treatment.

Regulatory Accounting – Gulf South is regulated by the Federal Energy Regulatory Commission (“FERC”). Gulf South does not apply Statement of Financial Accounting Standards (“SFAS”) No. 71, Accounting for the Effects of Certain Types of Regulation, (“SFAS No. 71”), which provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it reasonable to assume that such rates can be charged and collected. Competition in Gulf South’s market area often results in discounts off the maximum allowable rate. Accordingly, the application of SFAS No. 71 is not appropriate.

Cash and Cash Equivalents – Cash and cash equivalents consist primarily of cash on deposit, certificates of deposit, and money market accounts with original maturities of three months or less. All highly liquid investments with original maturities of three months or less are classified as cash and cash equivalents.

Margin and Collateral Deposits – Margin and collateral deposits consist primarily of cash that the Partnership has on deposit with counterparties for margin or collateral requirements related to trading futures, swap, and option contracts. Pursuant to the Partnership’s contracts with each counterparty, the margin or collateral on deposit will vary based on changes in market prices, the Partnership’s credit rating, and various other factors. As further discussed in Note 7, “Concentrations of Credit Risk,” the Partnership also requires collateral from their counterparties based on similar criteria. Amounts from financial instruments received as collateral from counterparties are recorded as “collateral held on deposit.”

Accounts Receivable-Trade – Accounts receivable-trade are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts receivable, and represent claims against third parties that will be settled in cash. An allowance for doubtful accounts is established when needed based on factors including historical experience with the particular counterparty, economic trends and conditions, the age of the underlying receivable, and the Partnership’s ability to exercise the right of offset. Interest receivable on delinquent accounts receivable is included in the accounts receivable-trade balance and recognized as interest income when contractually permissible and collectibility is reasonably assured. Past due accounts receivable-trade are written off when either internal collection efforts have been unsuccessful or when a settlement is reached for an amount that is less than the outstanding historical balance.

Transportation and Exchange Receivables and Payables – Transportation and exchange receivables and payables result from differences in gas volumes received and delivered by Gulf South. Such receivables and payables are valued in accordance with Gulf South’s tariff at market indices for the production month during which the receivables and payables were created. Customers can settle transportation and exchange receivables and payables with cash or in-kind payment, or by trading imbalances with other shippers. Receivables and payables, which will be settled in-kind, are valued monthly at market. The net gas imbalance resulting from these transactions is recorded as an asset or liability, as appropriate.

Natural Gas Inventory – Pipeline Services – Retained fuel and excess gas available for resale are classified as inventory and are valued at the lower of weighted-average cost or market. Volumes in storage held on behalf of others as of December 31, 2003 and 2002, were 47.0 bcf and 41.1 bcf, respectively. Such volumes are excluded from Gulf South’s inventory.

Natural Gas Inventory – Trading Services – Trading inventory is comprised of natural gas held for resale. As further discussed in Note 3, “Changes in Accounting Principles and New Accounting Pronouncements,” the Partnership adopted Emerging Issues Task Force (“EITF”) Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities (“EITF No. 02-3”). As such, inventory as of December 31, 2003 and 2002, acquired subsequent to October 25, 2002, is recorded at the lower of weighted-average cost or market, including a lower of cost or market write-down of $2 million as of December 31, 2002. Inventory acquired prior to the aforementioned adoption of EITF No. 02-3 is valued at market. The Partnership treated the adoption of EITF No. 02-3 related to trading inventory prospectively, as allowed, because it did not have sufficient information to report the change in a manner similar to a cumulative effect of a change in accounting principle.

Included in other current assets are amounts related to natural gas volumes held in third-party facilities and for which title has transferred to such third parties, but to which the Partnership has rights in the future. Such amounts are recorded at the lower of weighted-average cost or market based on the notional volumes to which the Partnership has rights. The Partnership may hold title to other natural gas volumes to which third parties have the rights to under similar arrangements. The amounts related to these transactions are recorded in other current liabilities and are carried at market or weighted-average cost, whichever is higher.

Trading and Risk Management Activities – Pipeline Services – In accordance with the Partnership’s risk management policy, Gulf South utilizes natural gas futures, swap, and option contracts (collectively, the “hedge contracts”) to hedge certain exposures to market price fluctuations on the upcoming years’ anticipated sales of excess gas inventory. The changes in the fair value of the hedge contracts are expected to, and do, have a high correlation to changes in the anticipated sales prices of excess gas inventory and, therefore, qualify as cash flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”). In addition, if the hedge contracts cease to have high correlation, or if the forecasted sale is deemed no longer probable to occur, hedge accounting is terminated and the associated changes in fair value of the derivative financial instruments are recognized in the related period of change as “Retained fuel and other revenues” on the consolidated statements of income.

The hedge contracts are reported in the consolidated balance sheets at fair value in “Other current assets and liabilities.” The related gains or losses derived from changes in the fair value of the hedge contracts are deferred in Partners’ capital (as a component of accumulated other comprehensive income). These deferred gains and losses are recognized as "Retained fuel and other revenues" on the consolidated statements of income when the excess gas inventory is sold. However, to the extent that the change in the fair value of the hedge contracts does not effectively offset the change in the fair value of the anticipated sales prices of excess gas inventory, the ineffective portion of the hedge contracts is immediately recognized as “Retained fuel and other revenues.”

As of December 31, 2003, Gulf South has included a net deferred loss on these cash flow hedges in “Accumulated other comprehensive income” of approximately $1 million. Gulf South expects to reclassify the entire amount to “Retained fuel and other revenues” over the next 12 months. Such amounts were immaterial for the year ended December 31, 2002, and the eleven months ended December 31, 2001. For the years ended December 31, 2002 and 2003, and the eleven months ended December 31, 2001, the ineffective portion of these hedges was immaterial.

Trading and Risk Management Activities – Trading Services – EKT offers risk management services to the natural gas, power, and weather markets, and optimization services related to the natural gas storage and transportation assets of its customers. These services are provided through a variety of financial instruments, including forward contracts involving cash settlement or physical delivery of natural gas or power; swap contracts requiring payment to (or receipts from) counterparties based on the difference between two prices for (or related to) natural gas, power, or weather; and option contracts requiring payment to (or receipts from) counterparties based on the difference between the option’s strike and the related market price for natural gas, power, or weather.

As required by EITF No. 02-3, the mark-to-market method is used to account for all derivative trading activities and the accrual method of accounting is used to account for storage, transportation, and asset optimization contracts not qualifying as derivatives under SFAS No. 133 and executed subsequent to October 25, 2002. The accounting method used for these non-derivative contracts executed prior to and up to that date was changed from the mark-to-market method to the accrual method on January 1, 2003. See Note 3, “Changes in Accounting Principles and New Accounting Pronouncements.”

As required by EITF Issue No. 99-2, Accounting for Weather Derivatives (“EITF No. 99‑2”), the Partnership uses the mark-to-market method to account for all trading related weather contracts.

Under the mark-to-market method, derivative contracts are recorded at quoted or estimated market value, with resulting unrealized gains and losses recorded as “Assets from trading activities” and “Liabilities from trading activities,” respectively, on the consolidated balance sheets according to their term to maturity. Current period changes in the assets and liabilities from trading activities are recognized as net gains or losses in “Net gain from trading activities” on the consolidated statements of income. Changes in the assets and liabilities from trading activities result primarily from changes in the valuation of the portfolio of contracts, maturity and settlement of contracts, and newly originated transactions. Terms regarding cash settlement of the contracts vary with respect to the actual timing of cash receipts and payments. Accounts receivable, accounts payable, and margin and collateral deposits include settlement amounts for financial derivatives for which the contractual settlement price has been published at the end of the accounting period. As a result, at December 31, 2003, accounts receivable and accounts payable included $88.2 million and $64 million, respectively, of January 2004 settled financial forward contracts valued using the published January 2004 futures price. At December 31, 2002, accounts receivable and accounts payable include $101.9 million and $97.9 million, respectively, of January 2003 settled financial forward contracts valued using the published January 2003 futures price. Margin and collateral deposits include $(1.9) million and $67.3 million of January 2003 and January 2004 settled futures, at December 31, 2003 and December 31, 2002, respectively.

The market prices and models used to value the derivatives reflect management’s best estimate considering various factors, including closing exchange and over-the-counter quotations, time value, and volatility underlying the contracts. The values are adjusted to reflect the potential impact of liquidating EKT’s position in an orderly manner over a reasonable time period under present market conditions and to reflect other types of risks, including model risk and credit risk. When quoted market prices are not available, EKT utilizes other valuation techniques to estimate market value. The use of these techniques requires EKT to make estimations with respect to future prices, volatility, liquidity, and other variables. Changes in market prices and management’s estimations directly affect the estimated market value of these transactions. Accordingly, it is reasonably possible that such estimates could change in the near term.

Beginning January 1, 2003, EKT US utilizes futures contracts to mitigate the variability in cash flows of anticipated future natural gas purchases and sales and accounts for these derivatives as cash flow hedges and has designated these contracts as hedges in accordance with SFAS No. 133. The changes in the fair value of the hedge contracts are expected to, and do, have a high correlation to changes in the anticipated natural gas purchases and sales and, therefore, qualify as cash flow hedges under SFAS No. 133. In addition, if the hedge contracts cease to have high correlation or if the forecasted purchase or sale are deemed no longer probable to occur, hedge accounting is terminated and the associated changes in fair value of the derivatives are recognized in the related period of change in “Net gain from trading activities” on the consolidated statements of income.

The natural gas derivatives of EKT US designated as hedges have an average term of less than one year, with the maximum term being two years. Contract terms represent the span of time over which EKT US is hedging its exposure to variability in future cash flows from the purchase and sale of natural gas.

The fair value of these derivatives are reported in the consolidated balance sheets in “Assets and liabilities from trading activities.” As of December 31, 2003, EKT US has included a net deferred loss on these cash flow hedges in “Accumulated other comprehensive income” of approximately $11.8 million. EKT US expects to reclassify approximately $1.3 million of deferred loss to “Net gain from trading activities” over the next 12 months. For the year ended December 31, 2003, the ineffective portion of these hedges recorded in “Net gain from trading activities” was approximately $5 million.

EKT’s asset optimization contracts relate to the natural gas storage and transportation assets of the related counterparties. Revenues, costs, and profit-sharing obligations associated with these asset optimization contracts are recognized based on the terms of the contract as such revenues are earned, costs are incurred, and when profit-sharing obligations arise. In addition, EKT enters into derivative contracts to manage market risk associated with its asset optimization contracts. These derivative contracts have not been designated as hedges and continue to be recorded at fair value.

All of EKT’s derivative transactions are subject to the Partnership’s risk management policy, which includes monitoring the creditworthiness of each counterparty. To the extent that a counterparty in these transactions is unable to meet its settlement commitments, the Partnership’s exposure to credit risk increases.

Trading and Risk Management Activities – Treasury – Pursuant to SFAS No. 133, the Partnership accounts for changes in the fair value of treasury related derivative instruments depending on whether they have been designated and qualify as part of a hedging relationship and, further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, the Partnership designates the hedging instrument, based upon the exposure being hedged, as a fair value hedge or cash flow hedge.

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative instrument is reported as a component of “Other comprehensive income” and reclassified into earnings in the same line item associated with the forecasted transaction in the same period or periods during which the hedged transaction affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized in current earnings during the period of change. For derivative instruments not designated as hedging instruments, the gain or loss is recognized in current earnings during the period of change.

The Partnership has entered into an interest rate swap agreement for interest rate risk exposure management purposes, which has been designated as a fair value hedge pursuant to SFAS No. 133. The interest rate swap agreement utilized by the Partnership effectively modifies the Partnership’s exposure to interest risk by converting the Partnership’s $200 million in fixed rate debt issued August 21, 2003, to a floating rate. This agreement involves the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount.

Hedge effectiveness is assessed as the change in the fair value of the hedging instrument relative to the change in the fair value of the related debt. During the year ended December 31, 2003, the Partnership recognized an immaterial net gain, included as a component of interest income, related to the ineffective portion of its fair value hedge of interest rate risk exposure. The effect of the fair value hedge for the year ended December 31, 2003, was to increase the carrying value of the associated debt by $2.5 million. A corresponding asset in approximately the same amount has been recorded in “Other assets”. On December 31, 2003, there were no hedged firm commitments that did not qualify as fair value hedges.

Additionally, the Partnership enters into forward foreign currency swaps associated with certain intercompany debt balances carried by the domestic entity and which are denominated in British pound. The swaps are used to counteract the effects of changes in foreign currency exchanges rates. For the year ended December 31, 2003, the foreign currency swaps resulted in a loss of $14.5 million.

Property, Plant, and Equipment – Property, plant, and equipment, including the working gas and base gas necessary to operate the pipeline, are recorded at historical cost or at the value established at the time of the Partnership inception. Construction costs and expenditures for major renewals and improvements, which extend the lives of the respective assets, are capitalized. Expenditures for maintenance, repairs, and minor renewals and improvements are charged to expense as incurred. Pipeline facilities are depreciated using the straight-line method based on average useful lives ranging from 4 to 30 years. Depreciation of constructed assets begins when the asset is placed in service. Computer hardware and software are depreciated using the straight‑line method based on average useful lives ranging from three to five years. Working gas and base gas are not depreciated.

The Partnership assesses impairment of its long-lived assets in accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

Intangible Assets – Intangible assets relate to the weather trading business and represent the logic utilized in the proprietary weather derivative valuation models, analytics that are used to translate weather information into trading strategies, and the proprietary data infrastructure that facilitates creation of structured weather derivative products. These intangible assets are amortized on a straight-line basis over a ten-year period and are included as “Other noncurrent assets” on the consolidated balance sheets.

Intangible assets are assessed annually for impairment. Indicators used by management to assess whether the intangible assets are impaired include a significant change in the extent or manner in which the intangible assets are used; a significant adverse change in the business climate that would affect the value of the intangible assets; an adverse action by a regulator, or a current-period operating or cash flow loss for the weather trading business, combined with a history of such that demonstrates continuing losses associated with the intangible assets derived from the weather trading business. There were no impairments of intangible assets for the years ended December 31, 2003 and 2002, and the eleven months ended December 31, 2001.

Income Taxes – The Partnership’s consolidated financial statements reflect no provision for United States federal and state income taxes since such taxes, if any, are the liabilities of the Partners. Foreign income taxes are provided for the Partnership’s subsidiaries, which are subject to taxation in foreign jurisdictions. Deferred tax assets and liabilities are recognized for the expected foreign tax consequences of the temporary differences between the tax bases of assets and liabilities and their financial statement carrying amounts in foreign jurisdictions. Such deferred tax assets and liabilities are not significant at December 31, 2003 and 2002.

Revenue Recognition – Revenues for the transportation and storage of natural gas are recognized based on volumes received and delivered in accordance with contractual terms at the time the transportation or storage services are rendered. Retained fuel is a component of Gulf South’s tariff structure, which provides for the recovery of fuel amounts expensed by the pipeline as operations and maintenance costs. Retained fuel is recognized as “Retained fuel and other revenues” on the consolidated statements of income at market prices in the month of retention. Retained fuel revenues for the years ended December 31, 2003 and 2002, and the eleven months ended December 31, 2001, are $54.1 million, $26.7 million, and $41.6 million, respectively.

Net Gain From Trading Activities – The accompanying consolidated financial statements present revenues, costs, and realized and unrealized gains and losses from derivatives for trading services on a net basis in “Net gain from trading activities” in the consolidated statements of income. Revenues from sales of physical natural gas and power are recognized in the month of delivery. The associated costs including transportation and transmission charges are recognized concurrent with the revenue.

Foreign Currency – Management has determined the functional currency of EKT Europe to be the British pound. As such, the assets and liabilities of EKT Europe are translated at the exchange rate on the consolidated balance sheet date. Revenues and expenses for EKT Europe are translated at a weighted-average exchange rate for the financial reporting period then ended. Foreign currency translation adjustments are reported in Partners’ capital (as a component of other comprehensive income). Individually significant transactions are translated at the exchange rate on the date of the transaction. Foreign exchange transaction gains and losses are recognized as “Other income (expense)” on the consolidated statements of income of the period. For the years ended December 31, 2003 and 2002, and the eleven months ended December 31, 2001, foreign exchange gains of approximately $1.3 million, $7.1 million, and $0.4 million, respectively, are included in “Other income (expense).”

Use of Estimates – The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make various assumptions and estimates that affect amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. See related discussion in “Trading and Risk Management Activities.”

Reclassifications – Certain reclassifications have been made to the presentation of balances from prior periods to conform with the current-period presentation. These reclassifications have no effect on previously reported results of operations.

3. Changes in Accounting Principles and New Accounting Pronouncements

Changes in Accounting Principles

EITF No. 02-3 – In October 2002, the EITF reached consensus in EITF No. 02-3 to rescind EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (“EITF No. 98-10”), EITF Issue No. 00-17, Measuring the Fair Value of Energy-Related Contracts in Applying No. 98-10, and Financial Accounting Standards Board (“FASB”) Staff Announcement Topic D-105, Accounting in Consolidation for Energy Trading Contracts, between Affiliated Entities When Activities of One but Not Both Affiliates Are within the Scope of EITF Issue No. 98‑10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“Topic No. D-105”). According to the consensus, “other energy contracts” such as storage and transportation contracts, not qualifying as derivatives pursuant to SFAS No. 133 executed prior to October 26, 2002, shall no longer be marked-to-market effective January 1, 2003. The accrual basis of accounting is required for contracts executed subsequent to October 25, 2002. In addition, for fiscal years beginning after December 15, 2002, gains and losses on all derivative instruments should be shown net in the income statement, whether or not settled physically, if the derivatives are held for trading purposes. EITF No. 02-3 also clarified that with the rescission of EITF No. 98-10, it would no longer be an acceptable industry practice to account for inventory held for trading purposes at fair value when fair value exceeds cost, except as provided by higher level accounting principles generally accepted in the United States. Application of EITF No. 02-3, in relation to restating the carrying value of inventory, may be applied prospectively if there is insufficient information to report a change in accounting for inventory in a manner similar to a cumulative effect of a change in accounting principle.

The Partnership prospectively adopted the provisions of EITF No. 02-3 related to inventory held for trading purposes and energy trading contracts, not qualifying as derivatives, and executed subsequent to October 25, 2002. The Partnership adopted EITF No. 02-3 in January 1, 2003 for its nonderivative energy trading contracts executed prior to October 26, 2002, and reported an increase to net income of $14.7 million as a cumulative effect of a change in accounting principle, net of tax. As a result of the adoption of EITF No. 02-3, the Partnership no longer recognizes energy trading contracts under mark-to-market accounting unless these contracts meet the definition of a derivative in accordance with SFAS No. 133 or the contract is a weather derivative. The Partnership has retained net presentation of all of its trading activities in the consolidated statements of income. The Partnership estimates that the adoption of EITF No. 02-03 negatively impacted after-tax earnings for the year ended December 31, 2003, by approximately $90 million.

In November 2002, EITF 02-3 was revised to state that an unrealized gain or loss at inception of a derivative instrument should not be recognized unless the fair value of that instrument is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique incorporating observable market data. Adoption by the Partnership of this November revision to EITF 02-3 was applied by the Partnership prospectively and did not have a material impact on the Partnership’s consolidated financial position or results of operations.

SFAS No. 143 – On January 1, 2003, the Partnership also adopted SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). SFAS No. 143 requires legal obligations associated with retirement of long-lived assets to be recognized at their fair value at the time the obligations are incurred. The liability is reported at fair value and is adjusted in subsequent periods as accretion expense is recorded. Corresponding retirement costs are capitalized as part of the carrying amount of the related long-lived asset and depreciated over the useful life of the asset. The Partnership has identified a legal obligation associated with the abandonment of its offshore pipeline laterals. Pursuant to federal regulations, the Partnership may have a legal obligation to plug and abandon pipelines, and remove platforms, once gas flow has ceased.

Upon adoption of SFAS No. 143, the Partnership recorded an additional long-term liability of $1.9 million, for a total long-term liability of $3.5 million related thereto, and a net property, plant, and equipment asset of $2.4 million at January 1, 2003. This resulted in a cumulative effect of a change in accounting principle of $0.5 million. Accretion and depreciation expense subsequent to the adoption SFAS No. 143 decreased net income by $0.5 million for the year ended December 31, 2003.

SFAS No. 144 – In August 2001, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS No. 144”), was issued. This statement supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to be Disposed Of. SFAS No. 144 retains the applicability to discontinued operations, and broadens the presentation of discontinued operations to include a component of an entity. The statement is being applied prospectively and initial adoption of this statement on January 1, 2002, did not have any impact on the Partnership’s consolidated financial position or results of operations.

SFAS No. 142 – SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), which required goodwill and intangible assets with indefinite lives be assessed for impairment rather than amortized, was adopted by the Partnership on January 1, 2002, with no material impact on the Partnership’s consolidated financial position or results of operations.

Topic No. D105 – Topic No. D-105 was issued in November 2001. The Announcement stated that energy trading transactions or contracts (and any related mark-to-market gains and losses) between entities of the same consolidated group should be eliminated in consolidation. The Partnership adopted Topic No. D-105 on December 31, 2001. Upon adoption, income was reduced by approximately $11.3 million. Such reduction is reported as the effect of a change in accounting principle for the eleven months ended December 31, 2001. As a result of the change, net income of the Partnership for the eleven months ended December 31, 2001 is the same as if Topic No. D-105 had been adopted at the inception of the Partnership on February 1, 2001. Topic No. D-105 was superceded by EITF No. 02-3.

New Accounting Pronouncements

FIN 46 – In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51 (“FIN 46”), as revised in December 2003. FIN 46 addresses consolidation by business enterprises of variable interest entities (“VIEs”). The primary objective of the FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses, if they occur, receive a majority of the entity’s expected residual returns, if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its VIEs in making this determination. The Partnership is required to fully adopt the provisions of FIN 46 as of January 1, 2005, and continues to evaluate the impact that adoption will have on its financial statements.

SFAS 149 – In April 2003, SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”) was issued. SFAS No.149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative as discussed in SFAS No. 133. In addition, it clarifies when a derivative contains a financing component that warrants special reporting in the statement of cash flows. SFAS No. 149 amends certain other existing pronouncements. Those changes will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. SFAS No. 149 was effective for contracts entered into or modified after June 30, 2003, except as stated below, and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively. The provisions of SFAS No. 149 that relate to SFAS No. 133, Implementation Issues, that have been effective for periods that began prior to June 15, 2003, continue to be applied in accordance with their respective effective dates. The adoption of SFAS No. 149 did not have an impact on the consolidated financial statements of the Partnership.

4. Accumulated Other Comprehensive Income (Loss)

The components of accumulated other comprehensive income are as follows:

	December 31, 2003			December 31, 2002			December 31, 2001
	General Partner	Limited Partners	Total	General Partner	Limited Partners	Total	General Partner	Limited Partners	Total
	(In Thousands)

Accumulated other comprehensive income:
Accumulated foreign currency translation	$ 109	$ 10,762	$ 10,871	$ 40	$ 3,938	$ 3,978	$ 3	$ 332	$ 335
Accumulated net cash flow hedge (loss) gain	(51)	(5,013)	(5,064)	82	8,101	8,183	56	5,558	5,614
Accumulated net cash flow hedge gain recognized in net income	(79)	(7,779)	(7,858)	(82)	(8,101)	(8,183)	(42)	(4,146)	(4,188)
	$ (21)	$ (2,030)	$ (2,051)	$ 40	$ 3,938	$ 3,978	$ 17	$ 1,744	$ 1,761

5. Supplemental Cash Flow Information

Changes in the components of working capital are as follows:

	Year Ended December 31,		Eleven Months Ended December 31,
	2003	2002	2001
	(In Thousands)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, trade	$ (91,225)	$ (262,697)	$ 470,246
(Increase) decrease in accounts receivable, affiliate	(7,238)	(8,387)	12,505
Decrease in receivable from partners	891	3,731	32,028
Change in net transportation and exchange receivables and payables	(5,111)	(1,461)	(20,663)
Change in net margin and collateral	(76,404)	4,056	114,489
Decrease (increase) in natural gas inventory	154,641	(168,327)	(185,953)
Increase (decrease) in accounts payable, trade	128,680	231,953	(347,780)
(Decrease) increase in accounts payable, affiliates	(24,300)	1,392	3,510
Increase (decrease) in accrued liabilities	42,934	(20,583)	70,575
Change in other current assets and liabilities, net	9,788	(153,334)	(5,653)
Total	$ 132,656	$ (373,657)	$ 143,304

Natural gas inventory at December 31, 2003, includes approximately $7 million related to excess gas volumes transferred from working gas.

6. Fair Value of Financial Instruments

At December 31, 2003 and 2002, the carrying amounts of certain financial instruments held by the Partnership, including cash equivalents, accounts receivable and payable, notes payable, and transportation and exchange receivables and payables, are representative of fair value because of the short-term maturity of these instruments. In addition to the financial instruments listed above, the Partnership held financial instruments for trading and risk management activities, as well as debt instruments.

The fair value of all of the Partnership’s derivative financial instruments and other trading contracts is the estimated amount at which management believes the instruments could be liquidated over a reasonable period of time, based on quoted market prices, current market conditions, or other estimates obtained from third-party brokers or dealers. See Note 2, “Significant Accounting Policies” under “Trading and Risk Management Activities,” for additional information.

The fair value of the Partnership’s derivatives, financial instruments, and other trading contracts at December 31, 2003 and 2002, is summarized in the following tables:

	December 31, 2003
	Estimated Fair Value		Carrying Amount
	Assets	Liabilities	Assets	Liabilities
	(In Thousands)

Trading⁽¹⁾
Natural gas	$ 499,610	$ 541,699	$ 499,610	$ 541,699
Power	348,267	296,814	348,267	296,814
Weather	20,069	21,177	20,069	21,177
Other energy-related commodities	5,013	6,722	5,013	6,722
	$ 872,959	$ 866,412	$ 872,959	$ 866,412
Non-Trading⁽²⁾
Interest rate swap	$ 2,058	$ –	$ 2,058	$ –
Natural gas	352	1,176	352	1,176
Foreign currency swap	–	1,497	–	1,497
	$ 2,410	$ 2,673	$ 2,410	$ 2,673

Debt instruments
Senior notes⁽³⁾	$ –	$ 546,252	$ –	$ 501,721

⁽¹⁾ Represents the fair value of all derivatives of trading services including natural gas derivatives for cash flow hedges accounted for in accordance with SFAS No. 133. The carrying amount of trading services derivatives is included in the consolidated balance sheet as “Assets and liabilities from trading activities.”

⁽²⁾ The carrying amount is included in the consolidated balance sheet in “Other current assets” and “Other current liabilities.”

⁽³⁾The estimated fair value of the senior notes has been determined by the Partnership using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the fair value estimate. The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair value.

	December 31, 2002
	Estimated Fair Value		Carrying Amount
	Assets	Liabilities	Assets	Liabilities
	(In Thousands)

Trading⁽¹⁾
Natural gas⁽²⁾	$ 545,976	$ 524,312	$ 545,976	$ 524,312
Power	192,891	120,692	192,891	120,692
Weather	15,811	14,459	15,811	14,459
Other energy related commodities	–	4,302	–	4,302
	$ 754,678	$ 663,765	$ 754,678	$ 663,765

Debt instruments
Senior notes⁽³⁾	$ –	$ 302,561	$ –	$ 299,222

⁽¹⁾ The carrying amount is included in the consolidated balance sheet as “Assets and liabilities from trading activities.”

⁽²⁾ Models used to fair value transportation, capacity, and storage agreements exclude optionality.

⁽³⁾ The estimated fair value of the senior notes has been determined by the Partnership using available market information and selected
valuation methodologies. Considerable judgment is required in interpreting market data to develop the fair value estimate. The use of
different market assumptions or valuation methodologies could have a material effect on the estimated fair value.

7. Concentrations of Credit Risk

EKT manages its own portfolio using a variety of financial instruments, which include forward, futures, swap, option, storage, and transportation contracts. EKT may attempt to balance its contractual portfolio in terms of notional amounts and the timing of performance and delivery obligations. However, net unbalanced positions often exist or are established based upon an assessment of anticipated market movements.

Inherent in the Partnership’s trading and risk management activities are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the contracts and derivative financial instruments will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or an agreement. The Partnership has established procedures in order to manage and control market and credit risk, and those control procedures are reviewed on an ongoing basis. The Partnership monitors market risk through a variety of techniques, including daily reporting of the change in the contracts and derivative financial instruments’ fair value to senior management. The Partnership attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures.

The notional volumes of the Partnership’s realized physical activity included in “Net gain from trading activities” are set forth below. These notional volumes represent the gross transaction volumes for trading contracts that are physically settled and are not a measure of the Partnership’s exposure to market or credit risk.

	Year Ended December 31,
	2003	2002
	(In Thousands)
Trading
Power (in MWh)	445,979	407,027
Gas (in MMBtu)	2,347,045	2,081,116

Financial instruments, which subject the Partnership to credit risk, consist principally of cash equivalents, trade receivables, and, as described above, derivative financial instruments and other energy trading contracts. In accordance with the Partnership’s investment policy, cash equivalents are invested such that credit exposure to any one financial institution is limited.

The Partnership’s operations are primarily concentrated in the energy industry. Trade receivables and other financial instruments are predominantly with energy, utility, and financial services-related companies, as well as other trading companies in the United States, the United Kingdom, Western Europe, and Canada. For the years ended December 31, 2003, 2002, and the eleven months ended December 31, 2001, no single counterparty contributed in excess of 10% of “Net gain from trading activities” on the consolidated statements of income.

The Partnership maintains credit policies that management believes minimize overall credit risk. Prospective and existing customers are reviewed for creditworthiness based upon pre-established standards, providing collateral and secured payment terms, as appropriate. Pursuant to these standards, the Partnership had cash collateral held on deposit of approximately $114.3 million and $168.0 million at December 31, 2003 and 2002, respectively.

The Partnership has master netting agreements in place that allow the Partnership to offset gains and losses arising from derivative instruments that may be settled in cash and/or gains and losses arising from derivative instruments that may be settled with the physical commodity. The Partnership’s policy is to have such master netting agreements in place with significant counterparties. Assets and liabilities (current and noncurrent) from trading activities, as well as trade accounts receivable and payable, reflect the master netting agreements in place.

The counterparties associated with “Assets from trading activities” at December 31, 2003 and 2002, are summarized in the following tables:

	December 31, 2003
	Investment Grade⁽¹⁾	Total
	(In Thousands)

Gas and electric utilities	$ 188,105	$ 211,220
Energy marketers	117,732	274,712
Financial institutions	285,879	300,805
Oil and gas producers	15,642	66,766
Industrials	10,570	11,746
Other	12,245	12,534
Total	$ 630,173	877,783
Credit valuation adjustments		(4,824)
Trading exposure⁽²⁾		872,959
Collateral		(379,735)⁽³⁾
Assets from trading activities, net of collateral		$ 493,224

⁽¹⁾ “Investment Grade” is primarily determined using publicly available credit ratings along with consideration of cash, collateral, standby letters of credit, and parent company guarantees. Included in “Investment Grade” are counterparties with a minimum, or a minimum implied through internal credit analysis, Standard & Poor’s or Moody’s rating of BBB- or Baa3, respectively.

⁽²⁾ Trading exposure reflects netting between current and noncurrent assets and liabilities from trading activities under master netting agreements, as applicable. Three customers’ exposure at December 31, 2003, comprised greater than 5% of assets from trading activities, of which two are included above as “Investment Grade.”

⁽³⁾ Includes collateral held on deposit and standby letters of credit. An additional $73.5 million of collateral is being applied against estimated accounts receivable.

	December 31, 2002
	Investment Grade⁽¹⁾	Total
	(In Thousands)

Gas and electric utilities	$ 168,790	$ 173,806
Energy marketers	146,241	219,644
Financial institutions	213,716	217,017
Oil and gas producers	74,289	115,095
Industrials	31,863	32,886
Other	126	128
Total	$ 635,025	758,576
Credit valuation adjustments		(3,898)
Trading exposure⁽²⁾		754,678
Collateral		(208,225)⁽³⁾
Assets from trading activities, net of collateral		$ 546,453

⁽²⁾ Trading exposure reflects netting between current and noncurrent assets and liabilities from trading activities under master netting agreements, as applicable. One customers’ exposure at December 31, 2002, comprised greater than 5% of assets from trading activities and is included above as “Investment Grade.”

⁽³⁾ Includes collateral held on deposit and standby letters of credit. An additional $49.7 million of collateral is being applied against estimated accounts receivable.

These concentrations of counterparties may impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory, or other conditions. Based on the Partnership’s policies, risk exposures, and valuation adjustments related to credit, the Partnership does not anticipate a material adverse effect on its consolidated financial position as a result of counterparty nonperformance.

8. Property, Plant, and Equipment

Property, plant, and equipment is summarized as follows:

	December 31,
	2003	2002
	(In Thousands)

Land	$ 712	$ 712
Pipeline facilities	861,661	806,656
Working gas and base gas	93,635	101,000
Computer hardware and software	63,077	52,843
Construction in progress	43,464	20,041
	1,062,549	981,252
Accumulated depreciation	(114,710)	(72,993)
Net property, plant, and equipment	$ 947,839	$ 908,259

9. Senior Notes and Credit Facilities

The Partnership’s debt is summarized as follows:

	December 31,
	2003	2002
	(In Thousands)
Short-term debt:
Entergy-Koch, LP Credit Agreement (364-Day)	$ –	$ 158,000
Entergy-Koch, LP Credit Agreement (Five-Year Term)	–	90,000
Entergy-Koch Trading, LP Margin Facility Agreement	25,000	–
Entergy-Koch Trading, Ltd. Short-Term Revolving Facility	7,337	–
Notes payable – credit facilities	$ 32,337	$ 248,000

Long-term debt:
Entergy-Koch, LP 3.65% Senior Notes due 2006, net of discount and including fair value adjustment	$ 202,408	$ –
Entergy-Koch, LP 6.90% Senior Notes due 2006, net of discount	299,313	299,222
Senior notes (net of discount)	$ 501,721	$ 299,222

Short-Term Debt

EKLP has historically maintained two primary credit facilities to manage their short-term cash requirements: a 364-day credit facility and a multi-year credit facility. In addition to these two facilities, Entergy-Koch Trading, LP and Entergy-Koch Trading, Ltd. have entered into short-term credit facilities for additional liquidity.

On December 19, 2003, EKLP renewed its 364-day credit facility with total commitments of $230 million. This facility includes the ability to issue up to $75 million of letters of credit within the total commitment of $230 million. At December 31, 2003, no loans or letters of credit were outstanding. At December 31, 2002, $158 million in loans were outstanding at a weighted-average interest rate of 2.08%. No letters of credit were outstanding. This facility expires on December 17, 2004.

On February 1, 2001, EKLP entered into a multi-year credit facility with total commitments of $105 million. This facility includes the ability to issue up to $105 million of letters of credit within the total commitment of $105 million. At December 31, 2003, no loans were outstanding under this facility, but $3.9 million in letters of credit were outstanding. At December 31, 2002, $90 million in loans were outstanding under this facility at a weighted‑average rate of 1.9% and $9.9 million in letters of credit were outstanding. This facility expires on February 1, 2006.

The interest rates and facility fees payable under the 364-day facility and on the multi-year facility vary based on the Partnership’s senior unsecured credit ratings and on the ratio of commitments utilized to the total commitments available under both facilities. At the Partnership’s current ratings, the applicable margin over LIBOR and facility fees payable are as follows:

	364-day		Multi-year
	Margin	Facility Fee	Margin	Facility Fee

Less than one-third utilization	0.475%	0.15%	0.350%	0.080%
More than one-third utilization	0.600%	0.15%	0.475%	0.080%

These facilities contain covenants that must be met in order to borrow, the most substantial of which is a limit on the ratio of consolidated total indebtedness to consolidated total capitalization of 55% or less.

On September 25, 2003, EKT US entered into a 364-day credit facility with a total commitment of $25 million. This facility may be used solely for the purpose of financing a portion of the Partnership’s margin requirements related to energy trading. Advances under the facility bear interest at LIBOR plus 0.75% and the Partnership is required to pay a facility fee at a rate of 0.125% per annum on the total commitment regardless of usage. As of December 31, 2003, $25 million was outstanding under this facility at a weighted-average interest rate of 1.85%. EKLP has guarantee obligations for EKT US under this facility. This facility contains covenants substantially similar to those in EKLP’s 364-day and multi-year credit facilities. This facility expires on September 23, 2004.

On December 1, 2003, EKT Europe entered into an uncommitted short-term credit facility with a limit of 10 million British pounds. This facility may be used for overdrafts and for money market loans. Overdrafts are repayable upon demand and money market loans are due at maturity. Advances under the facility bear interest at the bank’s cost of funds plus 0.75%. As of December 31, 2003, loans in the amount of 4.1 million British pounds ($7.3 million) were outstanding at a weighted‑average interest rate of 1.84%. EKLP has guarantee obligations for EKT Europe under this facility. This facility expires on April 24, 2004.

As of December 31, 2003, the Partnership was in compliance with all covenants under the facilities discussed above.

Long-Term Debt

On August 21, 2003, EKLP issued $200 million of senior unsecured notes at 3.65%, due August 20, 2006. These senior notes were offered at a discounted issue price of 99.955%, resulting in an effective interest rate of 3.67%. These senior notes rank equally with all other existing senior unsecured indebtedness of the Partnership. These senior notes are redeemable at the option of the Partnership, in whole or in part, upon not less than 30 days’ and not more than 60 days’ prior notice at a price equal to the greater of 100% of the principal amount or the present value of the remaining scheduled payments of principal and interest, exclusive of interest accrued to the date of redemption, at the applicable Treasury yield plus 25 basis points.

On July 24, 2001, EKLP issued $300 million of senior unsecured notes at 6.9%, due August 1, 2011. These senior notes were offered at a discounted issue price of 99.698%, resulting in an effective interest rate of 6.92%. These senior notes rank equally with all other existing unsecured indebtedness of the Partnership. These senior notes are redeemable at the option of the Partnership, in whole or in part, upon not less than 30 days’ and not more than 60 days’ prior notice at a price equal to the greater of 100% of the principal amount or the present value of the remaining scheduled payments of principal and interest, exclusive of interest accrued to the date of redemption, at the applicable Treasury yield plus 20 basis points.

Other Credit Facilities

On October 31, 2003, EKT Europe entered into a 364-day credit facility with a commitment of 40 million British pounds. This facility may be utilized for the issuance of letters of credit and bank guarantees related to the trading activity of EKT Europe. At December 31, 2003, letters of credit/bank guarantees in the amount of 19.3 million British pounds were outstanding ($34.6 million). The letter of credit/bank guaranty fees paid under this facility vary based on the Partnership’s senior unsecured credit ratings. At the Partnership’s current ratings, the fee is 0.75% per annum on the total amount of credits outstanding from time-to-time. The Partnership is not required to pay a facility fee or utilization fee under this facility. This facility contains covenants substantially similar to those in the 364-day and multi-year facilities. This facility expires on October 29, 2004

On December 1, 2003, EKT Europe entered into an uncommitted short-term credit facility with a limit of 25 million British pounds. This facility may be used for the issuance of letters of credit and bank guarantees related to the trading activity of EKT Europe. At December 31, 2003, letters of credit/bank guarantees in the amount of 15.1 million British pounds were outstanding ($27.0 million). The letter of credit/bank guaranty fee is 0.675% per annum on the total amount of credits outstanding from time to time. EKT Europe is not required to pay a facility fee or utilization fee under this facility. This facility expires on April 24, 2004.

Debt Maturity Schedule

Aggregate maturities of the principal amount of debt for the next five years and in total thereafter are as follows (in millions):

2004	$ 32
2005	–
2006	200
2007	–
2008	–
Thereafter	300
Total	$ 532

10. Commitments and Contingencies

Partnership Matters

Litigation – The Partnership is party to various legal actions arising in the normal course of business. Management believes that the disposition of outstanding legal actions will not have a material adverse impact on the Partnership’s consolidated financial position.

Environmental and Other Indemnification Matters – Koch Energy, Inc., indemnified the Partnership for all known environmental liabilities as of February 1, 2001, arising from conditions existing or events occurring at Gulf South operations prior to the inception of the Partnership. In addition, Koch Energy, Inc., and affiliates of Entergy have indemnified the Partnership for any unknown environmental liabilities that occurred prior to February 1, 2001, related to the respective assets contributed to the Partnership by such parties, which are identified before the tenth anniversary date of the Partnership’s formation. Any such environmental liabilities first identified prior to the sixth anniversary date are subject to a $50,000 per event deductible while those first identified after the sixth anniversary but before the tenth anniversary date are subject to a $1.0 million per event deductible.

All environmental liabilities arising from the operations of the Partnership subsequent to January 31, 2001, are the obligation of the Partnership. Koch Energy, Inc., and affiliates of Entergy have also agreed to indemnify the Partnership for all other losses and expenses the Partnership incurs in connection with any claim, litigation, or suit arising prior to the Partnership’s formation out of the operations of the Partners’ respective businesses or assets that the Partners contributed to EKLP.

Regulatory Matters– EKLP is subject to regulation by various federal, state, and local government agencies, and from time to time receives formal and informal requests for information from such agencies.

As an indirect partially owned subsidiary of Entergy, a registered holding company under the Public Utility Holding Company Act of 1935 (the “1935 Act”), EKLP generally must comply with certain requirements established in the 1935 Act, as well as rules and orders issued by the Securities and Exchange Commission under the 1935 Act that are applicable to investments by Entergy in non-utility companies.

The transportation of natural gas in interstate commerce is subject to regulation by the FERC under the Natural Gas Act and, to a lesser extent, the Natural Gas Policy Act of 1978, as amended. The FERC has jurisdiction over setting a pipeline’s rates, terms, and conditions of service, and the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion, or abandonment.

At the federal level, the FERC regulates certain activities of EKT regarding energy commodity transportation and wholesale trading. EKT is also subject to certain aspects of the jurisdiction of the Commodity Futures Trading Commission (“CFTC”).

EKT Matters

Commodity Futures Trading Commission Matter– On March 26, 2003, the FERC published a “Final Report on Price Manipulation in Western Markets,” focusing on gas and power activity in California. EKT was listed in the FERC report among the entities that had allegedly engaged in so-called “wash trading” in the gas markets with respect to 61 pairs of trades. In addition, EKT received a subpoena from the CFTC seeking certain information about its gas and power business, relating to so-called “wash trades,” and about information furnished to energy industry publications. EKT also received a document request in connection with an informal inquiry by the Securities and Exchange Commission (the “SEC”) relating to so-called “wash trades.”

On January 28, 2004, the CFTC approved an order settling the administrative action relating to the CFTC’s investigation. EKT agreed to pay a civil penalty of $3 million without admitting or denying the CFTC’s findings and has recorded such amount in the accompanying consolidated financial statements. The order cites EKT for reporting false price information. There were no findings of price manipulation, attempted price manipulation, or wash trading made against EKT or the Partnership. The CFTC notified EKT that this settlement concluded the issues that were subject of their investigation. In filing this order, the CFTC noted EKT’s cooperation in this matter. The order requires EKT’s continued cooperation with the CFTC.

Cornerstone Matter – On August 18, 2003, Cornerstone Propane Partners, LP filed suit against EKT and other entities on behalf of a putative class of persons who purchased and/or sold natural gas futures and options contracts on the New York Mercantile Exchange (“NYMEX”) between January 1, 2000 to December 31, 2002. On November 14, 2003, Dominick Viola filed a similar complaint, naming EKT. On November 25, 2003, the District Court for the Southern District of New York consolidated these cases with two other cases, neither of which named EKT as a defendant. On January 20, 2004, the plaintiffs filed a consolidated class action complaint which alleges violations of the Commodity Exchange Act including manipulation (Section 9(a)), wash trades (Section 4c), and aiding and abetting violations of the Act (Section 22(a)). On February 19, 2004, the defendants, including EKT, filed a motion to dismiss this consolidated complaint. EKT intends to vigorously defend this action.

Other – In addition, EKT has received several formal and informal requests for information from various regulatory and governmental agencies in connection with the Partnership’s gas and power businesses. At this point the Partnership does not believe that these inquiries will result in a material impact on the Partnership.

Gulf South Matters

Napoleonville Salt Dome Matter – On or about December 24, 2003, natural gas was observed bubbling at the surface near two solution-mined salt caverns leased and operated by Gulf South for natural gas storage in Napoleonville, Lousiana. Gulf South commenced remediation efforts immediately. Those remediation efforts are ongoing. Additionally, two class action lawsuits have been filed to date relating to this incident, a declaratory judgment action has been filed against Gulf South by the lessor of the property, and it is reasonably possible that additional actions may be filed against Gulf South. Included in these consolidated financial statements is a liability for estimated costs of approximately $14 million, which have been expensed, related to this matter.

Gulf South’s insurance policies provide for contractual reimbursements for, among other things, property damage, remediation costs, and third-party claims; and the Partnership may receive insurance reimbursements for substantially all costs incurred in excess of the deductibles underlying its policies. At this point in time, none of the insurers have declined coverage, although not all of the insurers have agreed to reimburse Gulf South for all costs and losses incurred above the deductibles underlying its insurance policies. The Partnership is vigorously pursuing its insurance claims, and any recovery under Gulf South’s insurance policies will be recorded when realization becomes probable.

While Gulf South believes its cost estimates are reasonable, it is possible that as additional facts become available, additional charges may be required. At this time, Gulf South cannot assess whether future costs, if any, will be material in the period in which they are recorded.

Wyble Lawsuit – On July 26, 2002, the following lawsuit was filed against Gulf South Pipeline Company, LP, and GS Pipeline Company, LLC, both subsidiaries of EKLP: Joseph Wyble, Robert May, Robert Hames, and Winston Land & Cattle Company, Inc. vs. Gulf South Pipeline Company, LP and GS Pipeline Company, LLC; Civil Action No. 9:02 CV 200 In the United States District Court for the Eastern District of Texas, Lufkin Division. This lawsuit involved allegations that Gulf South violated the federal Natural Gas Pipeline Safety Act (“PSA”) and sought injunctive and other relief to prevent Gulf South’s alleged continuation of unsafe operating practices in violation of the PSA. A hearing on Gulf South’s motions for partial summary judgment, which sought to limit the scope of the trial, was held on February 20, 2004. On March 3, 2004, Gulf South's motion for partial summary judgment was granted. The ruling indicated that plaintiffs did not have standing to bring an action for "remote violations" (i.e. violations which did not occur on their properties). This ruling substantially limited the scope of the case against Gulf South. On March 4, 2004, the parties entered into a memorandum of understanding that agreed to settle the action pursuant to confidential terms that were not material to the partnership.

Non-Cancelable Operating Obligations

Optimization contracts – EKT is required to make specified minimum payments relative to optimizing certain customers’ natural gas storage and transportation assets. For the years ended December 31, 2003 and 2002, and eleven months ended December 31, 2001, approximately $30.5 million, $20.4 million, and $6.6 million, respectively, of these specified minimum payments were made. EKT’s minimum future commitments related to these items as of December 31, 2003, are as follows (in thousands):

	2004	$ 39,126
	2005	17,246
	2006	6,850
	2007	4,582
	2008	1,144
	Total	$ 68,948

Operating leases – EKLP has various noncancelable operating lease commitments extending through the year 2014. Total operating lease expense for the years ended December 31, 2003 and 2002, and the eleven months ended December 31, 2001, were $6.3 million, $6.5 million, and $6.1 million, respectively. EKLP’s minimum future commitments related to these items as of December 31, 2003, are as follows (in thousands):

	2004	$ 5,579
	2005	5,590
	2006	5,568
	2007	5,324
	2008	5,074
	Thereafter	16,581
	Total	$ 43,716

11. Related-Party Transactions

EKT US is a party to an electric power purchase and sale agreement with an Entergy affiliate to provide various energy risk management services. For the years ended December 31, 2003 and 2002, and the eleven months ended December 31, 2001, EKT US received $3.5 million, $3.9 million, and $3.6 million, respectively, from the Entergy affiliate as reimbursement for the resources needed to provide these services.

EKT Europe was party to an Energy Management Agreement with Entergy affiliates whereby EKT Europe provides various risk management services for the Entergy affiliates. For the year ended December 31, 2002, and the eleven months ended December 31, 2001, EKT Europe received $0.9 million and $1.1 million, respectively, from the Entergy affiliate as reimbursement for the resources needed to provide these services. This agreement has expired and the amount received by EKT Europe for the year ended December 31, 2003 was immaterial.

At December 31, 2003, in assets and liabilities from trading activities are assets of $15.5 million and liabilities of $8.7 million relative to transactions with Entergy and Koch affiliates. At December 31, 2002, included in assets and liabilities from trading activities are assets of $30.0 million and liabilities of $28.9 million relative to transactions with Entergy and Koch affiliates.

Included in the net gain from trading activities for the year ended December 31, 2003, are affiliate revenues of $538.6 million (2.3% of trading revenues), affiliate cost of sales of $188.2 million (0.8% of trading cost of sales), and net realized affiliate gain of $17.7 million from financial instruments. Included in the net gain from trading activities for the year ended December 31, 2002, are affiliate revenues of $434.0 million (2.7% of trading revenues), affiliate cost of sales of $424.4 million (3.2% of trading cost of sales), and net realized affiliate loss of $9.0 million from financial instruments. Included in the net gain from trading activities for the eleven months ended December 31, 2001, are affiliate revenues of $466.3 million (4.8% of trading revenues), affiliate cost of sales of $607.9 million (6.2% of trading cost of sales), and net realized affiliate gain of $15.4 million from financial instruments.

EKLP has a building operating lease agreement with Entergy and Koch extending to the years 2014 and 2011, respectively. The Partnership had related rent expense of approximately $4.0 million, $3.1 million, and $2.6 million for the years ended December 31, 2003 and 2002, and the eleven months ended December 31, 2001, respectively.

Gulf South has trade receivables with an affiliate, Entergy, in the amounts of $0.6 million and $0.6 million as of December 31, 2003 and 2002, respectively. Gulf South provided transportation and storage services to Entergy and related companies in the amount of $7.7 million and $8.1 million for the years ended December 31, 2003 and 2002, respectively.

Additionally, the Partnership purchased information technology services from a Koch affiliate in the amount of $11.2 million, $12.0 million, and $9.4 million, for the years ended December 31, 2003, 2002, and the eleven months ended December 31, 2001, respectively.

Included in receivables from Partners at December 31, 2003, are amounts related to certain incentive compensation obligations that existed prior to the formation of the Partnership, which were paid by the Partnership. Such amounts are expected to be fully reimbursed by January 2004.

See also Note 12, “Partners’ Capital,” for indemnification provided by Entergy.

12. Partners’ Capital

The February 1, 2001, partners’ capital balances represent the Partnership’s consolidated financial position on its date of inception based on the contribution of cash and other monetary assets, contracts held for trading purposes, and property, plant, and equipment pursuant to the Amended and Restated Contribution Agreement for Entergy-Koch, LP, dated May 26, 2000, between certain wholly owned subsidiaries of the Partners.

The assets and liabilities contributed by Koch have been recorded at the Partnership’s estimate of fair value, subject to the total implicit fair value established by the net monetary assets contributed by Entergy.

The assets and liabilities contributed by Entergy, which are primarily assets from trading activities, have been recorded at the Partnership’s estimate of fair value, except for property, plant, and equipment, which was recorded at Entergy’s book value. The following table illustrates how the assets and liabilities contributed by the Partners are adjusted to the fair value estimated by the Partnership at inception.

Entergy contributed the following assets to the Partnership:

	(In Thousands)
Monetary assets:
Cash	$ 160,486
Other working capital – net	(12,637)
Trade receivables purchased from Koch	306,969
Additional capital of $72.75 million due in three years or upon liquidation (at estimated present value)	60,872
Note payable to Entergy from Partnership	(106,000)
Total monetary contributions	409,690

Non-monetary assets – primarily assets from trading activities at estimated fair market value	31,635
Total contributed capital – Entergy	$ 441,325

Koch contributed the following assets to the Partnership:

	(In Thousands)

Capital of pipeline and trading business	$ 415,480
Repayment of capital of pipeline and trading business funded by EKLP borrowing non-recourse to Koch	(300,000)
Note payable to Koch from Partnership	(106,000)
Agreed return of capital of $72.75 million due upon contribution by Entergy (at estimated present value)	(60,872)
Net book deficit of contributed assets, after distributions	(51,392)
Fair value adjustment to the Koch contributed assets	461,082
Total contributed capital – Koch	$ 409,690
Total beginning equity	$ 851,015

In addition, the Partnership also paid Koch approximately $165.8 million at Inception relative to amounts due Koch, which were payables of the contributed trading business.

Upon Inception, the Partnership executed notes payable to Entergy Power International Holdings Corporation for $106 million and Koch Energy, Inc., for $106 million due on or before May 31, 2001. The notes were secured by certain receivables and contractual agreements of the Partnership. On March 29, 2001, the Partnership completely paid the $212 million of notes payable to the Partners with associated interest expense of $1.7 million.

Pursuant to the Partnership Agreement, one of the limited partners and one of the members of the general partner made a contribution of $72.7 million in January 2004. The equivalent amounts were distributed to the remaining limited partner and the other member of the general partner. In addition, in January 2004 certain assets of the Partnership were revalued to measure the economic impact to the Partners at this date. Such revaluation will not have any effect on the historical cost basis consolidated financial statements of the Partnership.

In 2002, EKLP had a contractual dispute with a counterparty and the resulting loss was indemnified by Entergy. In connection with the indemnification, the Partnership recorded a receivable from Entergy of $32.8 million and a corresponding contribution to capital in the accompanying statement of changes in partners’ capital as December 31, 2002. The $32.8 million was paid by Entergy to the Partnership on February 7, 2003. As part of the indemnification arrangement, beginning in January 2003, Entergy is entitled to all the benefits and detriments associated with the contractual agreements with the counterparty. EKLP continues to service the power needs of the counterparty on behalf of Entergy, and as a result of that arrangement, has a $2.8 million receivable (included in receivables from affiliates) from Entergy at December 31, 2003.

13. Employee Retirement Plans

For its domestic operations, the Partnership established the Money Purchase Pension Plan, which is available to all active employees meeting certain minimum requirements. This plan is a defined contribution plan subject to the provisions of the Employee Retirement Income Security Act of 1974 (“ERISA”). Under the terms of the plan, 4% of employees’ base compensation is contributed to the plan.

For its domestic operations, the Partnership also established the 401(k) Retirement Plan, which is available to all active employees. This plan is a defined contribution plan subject to the provisions of the ERISA. Under the terms of the plan, employees may contribute a percentage of their annual salary, subject to Internal Revenue Service limits, with the Partnership matching 100% of the first 6% contributed by employees with over one year of service.

For its European operations, the Partnership established a Group Personal Pension Plan, which is available to all active employees and is managed by Scottish Equitable. Under the terms of the plan, employees can contribute from 2% to 5% of their base compensation on a pretax basis. The Partnership will contribute from 3% to 8% of an employee’s base compensation depending on the amount that the employee contributes to the plan.

For its employees’ participation in these plans, the Partnership recorded expense for the years ended December 31, 2003, 2002, and the eleven months ended December 31, 2001, of approximately $4.5 million, $4.4 million, and $4.2 million, respectively. Partnership contributions to the above plans are subject to vesting requirements.

14. Taxes

EKT Europe is subject to UK taxes. The net income before income taxes and cumulative effect of change in accounting principle attributed to European operations for the years ended December 31, 2003, 2002, and the eleven months ended December 31, 2001, is $20.6 million, $9.8 million, and $10.7 million, respectively. The total income tax expense related to the net income before income taxes and cumulative effect of change in accounting principle that is attributed to foreign operations is $4.5 million, $3.7 million, and $3.5 million for the years ended December 31, 2003, 2002, and the eleven months ended December 31, 2001, respectively. Such income tax expense amounts were reflected as current income taxes. A tax benefit of $4.5 million is included in the cumulative effect of a change in accounting principle for the year ended December 31, 2003.

15. Business Segment Information

The Partnership has two operating business segments: pipeline services and trading services. Pipeline services provides gathering, transportation, and storage services for natural gas in the Gulf Coast region of the United States via its interstate pipeline. Trading services engages in physical and financial natural gas trading and weather trading throughout the United States, the United Kingdom, Western Europe, and Canada, as well as physical and financial power trading throughout the United States, the United Kingdom, and Western Europe. Trading services also provides asset optimization services in the United States. For segment reporting purposes, all of trading services’ operations have been aggregated as one reportable segment due to similarities in their operations as permitted by SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information. The non-operating segment consists of corporate activities.

The significant accounting policies of the segments are the same as those described in the summary of significant accounting policies as discussed in Note 2. The Partnership accounts for intersegment transactions at prices comparable to those received from unaffiliated customers and in some instances are affected by regulatory considerations.

Summarized financial information by segment is presented in the tables below. Reconciliations of total reportable segment amounts are reconciled to the consolidated totals following the tables.

	Year Ended December 31, 2003
	Trading Services	Pipeline Services	Total
	(In Thousands)
Natural gas pipeline revenues:
Revenues for reportable segments	$ –	$ 211,739	$ 211,739
Trading net gain:
Net gain for reportable segments	311,719(1)	–	311,719
Depreciation and amortization expense	11,790	31,061	42,851
Operating income	182,036	18,003	200,039
Interest income	3,046	1,110	4,156
Interest expense	(12,170)	(403)	(12,573)
Income taxes	4,494	–	4,494
Net income	185,258	18,107	203,365
Capital expenditures	8,579	79,698	88,277
Total assets at December 31, 2003	2,430,247(2)	1,025,398	3,455,645

⁽¹⁾ Includes net gain from trading activities from foreign operations of approximately $55.1 million principally attributed to EKT Europe.

⁽²⁾ Includes assets of $866.9 million of foreign operations principally attributed to European and Canadian

	Year Ended December 31, 2002
	Trading Services	Pipeline Services		Total
	(In Thousands)
Natural gas pipeline revenues:
Revenues for reportable segments	$ –		$ 205,236	$ 205,236
Trading net gain:
Net gain for reportable segments	197,372(1)		–	197,372
Depreciation and amortization expense	11,233		30,854	42,087
Operating income	69,783		73,868	143,651
Interest income	3,217		2,368	5,585
Interest expense	(8,176)		–	(8,176)
Income taxes	3,684		–	3,684
Net income	79,542		75,312	154,854
Capital expenditures	9,364		40,769	50,133
Total assets at December 31, 2002	2,353,102(2)		1,087,466	3,440,568

⁽¹⁾ Includes net gain from trading activities from foreign operations of approximately $28.8 million attributed to EKT Europe.

⁽²⁾ Includes assets of $678.3 million of foreign operations principally attributed to EKT Europe.

	Eleven Months Ended December 31, 2001
	Trading Services	Pipeline Services	Total
	(In Thousands)
Natural gas pipeline revenues:
Revenues for reportable segments	$ –	$ 183,059	$ 183,059
Trading net gain:
Net gain for reportable segments	234,685(1)	–	234,685
Depreciation and amortization expense	9,036	26,245	35,281
Operating income	146,233	62,978	209,211
Interest income	3,472	1,160	4,632
Interest expense	(7,635)	–	(7,635)
Income taxes	3,510	–	3,510
Net income	138,296	61,630	199,926
Capital expenditures	5,468	21,401	26,869
Total assets at December 31, 2001	1,748,844(2)	1,030,916	2,779,760

⁽¹⁾ Includes net gain from trading activities from foreign operations of approximately $22.9 million principally attributed to EKT Europe.

⁽²⁾ Includes assets of $499.8 million of foreign operations principally attributed to EKT Europe.

The reconciliations of natural gas pipeline revenues, net gain from trading activities, net income, and total assets for reportable segments to the consolidated totals are as follows:

	Year Ended December 31,		Eleven Months Ended December 31,
	2003	2002	2001
	(In Thousands)

Natural gas pipeline revenues
Total revenues for reportable segment	$ 211,739	$ 205,236	$ 183,059
Elimination of intersegment balances	(34,938)	(44,152)	(21,959)
Total natural gas pipeline consolidated revenues	$ 176,801	$ 161,084	$ 161,100

Net gain from trading activities
Total net gain for reportable segment	$ 311,719	$ 197,372	$ 234,685
Elimination of intersegment balances	27,643	62,100	23,062
Total consolidated net gain from trading activities	$ 339,362	$ 259,472	$ 257,747

Operating income
Total operating income for reportable segments	$ 200,039	$ 143,651	$ 209,211
Elimination of intersegment balances	(7,295)	17,948	1,103
All other	88	(6,370)	(2,716)
Total consolidated operating income	$ 192,832	$ 155,229	$ 207,598

Interest income
Total interest income for reportable segments	$ 4,156	$ 5,585	$ 4,632
Elimination of intersegment balances	(9,319)	(6,411)	(5,546)
All other	11,183	2,554	3,782
Total consolidated interest income	$ 6,020	$ 1,728	$ 2,868

Interest expense
Total interest expense for reportable segments	$ (12,573)	$ (8,176)	$ (7,635)
Elimination of intersegment balances	9,319	6,411	5,546
All other	(25,273)	(20,473)	(18,739)
Total consolidated interest expense	$ (28,527)	$ (22,238)	$ (20,828)

Net income
Total net income for reportable segments	$ 203,365⁽¹⁾	$ 154,854	$ 199,926
Elimination of intersegment balances	(7,295)	17,948	(10,227)⁽²⁾
All other	(15,960)	(23,542)	(17,618)
Total consolidated net income	$ 180,110	$ 149,260	$ 172,081

⁽¹⁾ Includes $15.2 million effect of change in accounting principle, net of tax. See Note 3, “Changes in Accounting Principles and New Accounting Pronouncements,” for additional information.

⁽²⁾ Includes $(11.3) million effect of change in accounting principle, net of tax. See Note 3, “Changes in Accounting Principles and New Accounting Pronouncements,” for additional information.

	December 31,
	2003	2002
Total assets
Total assets for reportable segments	$ 3,455,645	$ 3,440,568
Elimination of intersegment balances	(10,717)	6,545
All other	272,714	(10,898)
Total consolidated assets	$ 3,717,642	$ 3,436,215

Changes in Accounting Principles

New Accounting Pronouncements

Short-Term Debt

Long-Term Debt

Other Credit Facilities

Debt Maturity Schedule

Partnership Matters

EKT Matters

Gulf South Matters

Non-Cancelable Operating Obligations

Natural gas pipeline revenues

Total revenues for reportable segment

Elimination of intersegment balances

Total natural gas pipeline consolidated revenues

Net gain from trading activities

Total net gain for reportable segment

Elimination of intersegment balances

Total consolidated net gain from trading activities

Operating income

Total operating income for reportable segments

Elimination of intersegment balances

All other

Total consolidated operating income

Interest income

Total interest income for reportable segments

Elimination of intersegment balances

All other

Total consolidated interest income

Interest expense

Total interest expense for reportable segments

Elimination of intersegment balances

All other

Total consolidated interest expense

Net income

Total net income for reportable segments

Elimination of intersegment balances

All other

Total consolidated net income