a10-k.htm

NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications, with no effect on net income or common shareholders’ (or members’) equity.

Use of Estimates in the Preparation of Financial Statements

In conformity with generally accepted accounting principles, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.

Revenues and Fuel Costs

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.

Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate case as of the date the financial statements are prepared.

Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing.System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.

Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.

Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2010 and 2009, is shown below:

2010	Entergy	Utility	Entergy Wholesale Commodities	Parent & Other
	(In Millions)
Production
Nuclear	$8,393	$5,378	$3,015	$-
Other	1,842	1,797	45	-
Transmission	2,986	2,956	30	-
Distribution	5,926	5,926	-	-
Other	1,661	1,411	248	2
Construction work in progress	1,662	1,300	361	1
Nuclear fuel	1,378	760	618	-
Property, plant, and equipment - net	$23,848	$19,528	$4,317	$3

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

2009	Entergy	Utility	Entergy Wholesale Commodities	Parent & Other
	(In Millions)
Production
Nuclear	$8,105	$5,414	$2,691	$-
Other	1,936	1,724	212	-
Transmission	2,922	2,889	33	-
Distribution	5,948	5,948	-	-
Other	1,664	1,398	263	3
Construction work in progress	1,547	1,134	414	(1)
Nuclear fuel (leased and owned)	1,267	747	520	-
Property, plant, and equipment - net	$23,389	$19,254	$4,133	$2

Depreciation rates on average depreciable property for Entergy approximated 2.6% in 2010, 2.7% in 2009, and 2.7% in 2008. Included in these rates are the depreciation rates on average depreciable utility property of 2.5% in 2010, 2.7% in 2009, and 2.7% 2008, and the depreciation rates on average depreciable non-utility property of 3.7% in 2010, 3.8% in 2009, and 3.7% in 2008.

Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.

“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $207.6 million and $197.8 million as of December 31, 2010 and 2009, respectively.

Construction expenditures included in accounts payable at December 31, 2010 is $171 million.

Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 2010 and 2009, is shown below:

2010	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Millions)
Production
Nuclear	$1,029	$1,452	$1,489	$-	$-	$-	$1,408
Other	406	302	393	368	(2)	331	-
Transmission	837	456	597	469	22	569	6
Distribution	1,637	817	1,255	977	296	944	-
Other	197	192	289	207	180	116	20
Construction work in progress	114	119	521	147	12	80	211
Nuclear fuel	189	203	135	-	-	-	155
Property, plant, and equipment - net	$4,409	$3,541	$4,679	$2,168	$508	$2,040	$1,800

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

2009	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Millions)
Production
Nuclear	$1,017	$1,484	$1,450	$-	$-	$-	$1,463
Other	414	300	384	331	(6)	301	-
Transmission	819	416	611	467	27	543	6
Distribution	1,618	870	1,330	943	280	907	-
Other	202	185	307	220	174	113	21
Construction work in progress	115	84	510	63	21	82	199
Nuclear fuel (leased and owned)	185	163	122	-	-	-	85
Property, plant, and equipment - net	$4,370	$3,502	$4,714	$2,024	$496	$1,946	$1,774

Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy

2010	2.9%	1.8%	2.4%	2.6%	3.1%	2.3%	2.9%
2009	3.3%	1.9%	2.5%	2.6%	3.0%	2.3%	2.9%
2008	3.2%	2.2%	2.5%	2.6%	3.1%	2.4%	2.9%

Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $134 million and $131 million as of December 31, 2010 and 2009, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $2.5 million and $2.3 million as of December 31, 2010 and 2009, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $9.5 million and $9.2 million as of December 31, 2010 and 2009, respectively.

As of December 31, 2010, construction expenditures included in accounts payable are $16 million for Entergy Arkansas, $14.3 million for Entergy Gulf States Louisiana, $31.6 million for Entergy Louisiana, $6.8 million for Entergy Mississippi, $157.5 thousand for Entergy New Orleans, $3.3 million for Entergy Texas, and $23.8 million for System Energy.

System Energy invested, through its subsidiary Entergy New Nuclear Development, LLC, in initial development costs for potential new nuclear development at the Grand Gulf and River Bend sites, including licensing and design activities. As of December 31, 2009, $100.3 million in construction work in progress was recorded on System Energy’s balance sheet related to this project. In the first quarter 2010, $24.9 million, $24.9 million, and $49.5 million of this construction work in progress was transferred to Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy Mississippi, respectively.

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2010, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Generating Stations		Fuel-Type	Total Megawatt Capability (1)	Ownership	Investment	Accumulated Depreciation
					(In Millions)
Utility business:
Entergy Arkansas -
Independence	Unit 1	Coal	836	31.50%	$127	$94
	Common Facilities	Coal		15.75%	$33	$24
White Bluff	Units 1 and 2	Coal	1,659	57.00%	$489	$332
Ouachita (2)	Common Facilities	Gas		66.67%	$171	$140
Entergy Gulf States Louisiana -
Roy S. Nelson	Unit 6	Coal	550	40.25%	$243	$167
Big Cajun 2	Unit 3	Coal	588	24.15%	$142	$94
Ouachita (2)	Common Facilities	Gas		33.33%	$87	$72
Entergy Mississippi -
Independence	Units 1 and 2 and Common Facilities	Coal	1,678	25.00%	$247	$132
Entergy Texas -
Roy S. Nelson	Unit 6	Coal	550	29.75%	$178	$116
Big Cajun 2	Unit 3	Coal	588	17.85%	$106	$67
System Energy -
Grand Gulf	Unit 1	Nuclear	1,251	90.00%(3)	$3,852	$2,418

Entergy Wholesale Commodities:
Independence	Unit 2	Coal	842	14.37%	$68	$40
	Common Facilities	Coal		7.18%	$16	$10

(1)	“Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(2)	Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities.
(3)	Includes an 11.5% leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements.

Nuclear Refueling Outage Costs

Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.

Allowance for Funds Used During Construction (AFUDC)

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Income Taxes

Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreement. Deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.

Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.

Earnings per Share

The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:

	For the Years Ended December 31,
	2010			2009			2008
		(In Millions, Except Per Share Data)
Basic earnings per average common share	Income	Shares	$/share	Income	Shares	$/share	Income	Shares	$/share
Net income attributable to Entergy Corporation	$1,250.2	186.0	$6.72	$1,231.1	192.8	$6.39	$1,220.6	190.9	$6.39
Average dilutive effect of:
Stock options	-	1.8	(0.06)	-	2.2	(0.07)	-	4.1	(0.13)
Equity units	-	-	-	3.2	0.8	(0.02)	24.7	6.0	(0.06)
Diluted earnings per average common share	$1,250.2	187.8	$6.66	$1,234.3	195.8	$6.30	$1,245.3	201.0	$6.20

The calculation of diluted earnings per share excluded 5,380,262 options outstanding at December 31, 2010, 4,368,614 options outstanding at December 31, 2009, and 3,326,835 options outstanding at December 31, 2008 that could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.

See Note 7 to the financial statements for a discussion of the equity units.

Stock-based Compensation Plans

Entergy grants stock options to key employees of the Entergy subsidiaries, which is described more fully in Note 12 to the financial statements. Effective January 1, 2003, Entergy prospectively adopted the fair value based method of accounting for stock options. Awards under Entergy’s plans generally vest over three years. Stock-based compensation expense included in consolidated net income, net of related tax effects, is $9.2 million for 2010, is $10.4 million for 2009, and is $10.7 million for 2008 for Entergy’s stock options granted.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Accounting for the Effects of Regulation

Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body empowered to set rates that bind customers (its regulator); (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.

An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.

Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.

Cash and Cash Equivalents

Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.

Investments

Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. Effective January 1, 2009, Entergy adopted an accounting pronouncement providing guidance regarding recognition and

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

presentation of other-than-temporary impairments related to investments in debt securities. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 17 to the financial statements for details on the decommissioning trust funds and the other than temporary impairments recorded in 2010, 2009, and 2008.

Equity Method Investments

Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee’s assets were to be liquidated at book value. In accordance with this method, earnings are allocated to owners or members based on what each partner would receive from its capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.

Derivative Financial Instruments and Commodity Derivatives

The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Contracts for commodities that will be delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments.

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.

Impairment of Long-Lived Assets

Four nuclear power plants in the Entergy Wholesale Commodities business segment have applications pending for NRC license renewals. This includes the Vermont Yankee plant, which currently has an operating license that expires March 21, 2012. In addition to its federal NRC license, there is a two-step state law licensing process for obtaining a Certificate of Public Good (CPG) to operate Vermont Yankee and store spent nuclear fuel beyond March 21, 2012, when the current CPG expires. First, the Vermont legislature must vote affirmatively to permit the Vermont Public Service Board to consider Vermont Yankee’s application for a renewed CPG for the continued operation of Vermont Yankee and for storage of spent fuel. Second, the Vermont Public Service Board must vote to renew the CPG. On March 3, 2008, Entergy filed an application with the VPSB to renew its CPG. On February 24, 2010, a bill to approve the continued operation of Vermont Yankee was advanced to a vote in the Vermont Senate and defeated by a margin of 26 to 4. Neither house of the Vermont General Assembly has voted on a similar bill since that time.

Entergy Wholesale Commodities’ investments are subject to impairment if adverse market conditions arise, if a unit ceases operation, or for certain units if their operating licenses will not be renewed. Specifically regarding Vermont Yankee, if Entergy concludes that Vermont Yankee is unlikely to operate significantly beyond its current license expiration date in 2012, it could result in an impairment of part or all of the carrying value of the plant. Entergy's evaluation of the probability associated with operations of the plant past 2012 include a number of factors such as the status of the NRC's evaluation of Entergy's application for license renewal, the status of state regulatory issues as described above, the potential sale of the plant, and the application of federal laws regarding the continued operations of nuclear facilities. In preparing its 2010 financial statements Entergy evaluated these factors and concluded that the carrying value of Vermont Yankee is not impaired as of December 31, 2010. The net carrying value of the plant, including nuclear fuel, is $424 million as of December 31, 2010.

River Bend AFUDC

The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Reacquired Debt

The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, in accordance with ratemaking treatment.

Taxes Imposed on Revenue-Producing Transactions

Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.

Presentation of Non-Controlling Interests

In 2007, a new accounting pronouncement was issued regarding non-controlling interests that requires generally that ownership interests in subsidiaries held by parties other than the reporting company (non-controlling interests) be clearly identified, labeled, and presented in the consolidated balance sheet within equity, but separate from the controlling shareholders’ equity, and that the amount of consolidated net income attributable to the reporting company and to the non-controlling interests be clearly identified and presented on the face of the consolidated income statement. This new accounting pronouncement became effective for Entergy in the first quarter 2009 and applies to preferred securities issued by Entergy subsidiaries to third parties.

Presentation of Preferred Stock without Sinking Fund

In connection with the adoption of the new accounting pronouncement regarding non-controlling interests Entergy evaluated the accounting standards regarding the classification and measurement of redeemable securities. These standards require the classification of securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members’ equity.

The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Asset Management, whose preferred holders also have protective rights as described in Note 6 to the financial statements, are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

New Accounting Pronouncements

The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income or financial position.

NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Regulatory Assets

Other Regulatory Assets

Regulatory assets represent probable future revenues associated with costs that are expected to be recovered from customers through the regulatory ratemaking process affecting the Utility business. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the table below provides detail of “Other regulatory assets” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2010 and 2009:

Entergy

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$406.4	$403.9
Deferred capacity - recovery timing will be determined by the LPSC in the formula rate plan filings (Note 2 – Retail Rate Proceedings – Filings with the LPSC)	15.8	23.2
Grand Gulf fuel - non-current and power management rider - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery)	17.4	58.2
Gas hedging costs - recovered through fuel rates	1.9	0.4
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)	1,734.7	1,481.7
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b)	4.8	7.2
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	1,026.0	1,183.2
Removal costs - recovered through depreciation rates (Note 9) (b)	81.5	44.4
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	26.2	28.1
Sale-leaseback deferral - Grand Gulf Lease Obligation recovered through June 2014 and Waterford 3 Lease Obligation (in 2009) (Note 10 – Sale and Leaseback Transactions – Grand Gulf Lease Obligations and Waterford 3 Lease Obligations)	22.3	115.3
Spindletop gas storage facility - recovered through December 2032 (a)	32.6	34.2
Transition to competition costs - recovered over a 15-year period through February 2021	95.8	101.9
Little Gypsy cost proceeding – recovery timing will be determined by the LPSC in the project costs proceeding (Note 2 – Little Gypsy Repowering Project)	200.9	-
Unamortized loss on reacquired debt - recovered over term of debt	122.5	115.0
Other	49.4	50.5
Total	$3,838.2	$3,647.2

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Notes to Financial Statements

Entergy Arkansas

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$167.3	$179.4
Incremental ice storm costs - recovered through 2032	11.1	11.6
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)	547.5	447.6
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery)	-	8.2
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b)	4.8	7.2
Provision for storm damages - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	118.5	61.7
Unamortized loss on reacquired debt - recovered over term of debt	38.0	29.7
Other	5.2	1.6
Entergy Arkansas Total	$892.4	$747.0

Entergy Gulf States Louisiana

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$17.8	$17.6
Gas hedging costs - recovered through fuel rates	1.0	0.3
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b)	157.4	142.7
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	6.0	44.1
Deferred capacity - recovery timing will be determined by the LPSC in the formula rate plan filings (Note 2 – Retail Rate Proceedings – Filings with the LPSC)	14.0	15.7
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	26.2	28.1
Spindletop gas storage facility - recovered through December 2032 (a)	32.6	34.2
Unamortized loss on reacquired debt - recovered over term of debt	13.5	14.1
Other	2.4	3.0
Entergy Gulf States Louisiana Total	$270.9	$299.8

Entergy Louisiana

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$113.4	$99.9
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b)	309.1	200.4
Little Gypsy cost proceeding – recovery timing will be determined by the LPSC in the project costs proceeding (Note 2 – Little Gypsy Repowering Project)	200.9	-
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	1.0	91.9
Deferred capacity - recovery timing will be determined by the LPSC in the formula rate plan filings (Note 2 – Retail Rate Proceedings – Filings with the LPSC)	1.8	7.5
Sale-leaseback deferral - (Note 10 – Sale and Leaseback Transactions – Waterford 3 Lease Obligations )	-	40.7
Unamortized loss on reacquired debt - recovered over term of debt	22.5	19.7
Other	14.0	16.9
Entergy Louisiana Total	$662.7	$477.0

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Notes to Financial Statements

Entergy Mississippi

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$5.0	$4.7
Removal costs - recovered through depreciation rates (Note 9) (b)	46.1	44.5
Grand Gulf fuel - non-current and power management rider- recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery)	17.4	50.0
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)	160.0	131.5
Provision for storm damages - recovered through retail rates	8.7	10.0
Unamortized loss on reacquired debt - recovered over term of debt	11.5	10.1
Other	4.5	0.6
Entergy Mississippi Total	$253.2	$251.4

Entergy New Orleans

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$3.2	$3.0
Removal costs - recovered through depreciation rates (Note 9) (b)	15.4	15.2
Gas hedging costs - recovered through fuel rates	0.5	0.2
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)	95.3	74.8
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	10.8	23.8
Unamortized loss on reacquired debt - recovered over term of debt	3.0	2.9
Other	7.1	5.8
Entergy New Orleans Total	$135.3	$125.7

Entergy Texas

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$1.4	$1.5
Removal costs - recovered through depreciation rates (Note 9) (b)	7.3	7.2
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)	165.4	145.9
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	881.7	952.2
Transition to competition costs - recovered over a 15-year period through February 2021	95.8	101.9
Unamortized loss on reacquired debt - recovered over term of debt	12.7	13.5
Other	4.7	9.9
Entergy Texas Total	$1,169.0	$1,232.1

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

System Energy

	2010	2009
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$98.3	$97.8
Removal costs - recovered through depreciation rates (Note 9) (b)	12.2	13.9
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b)	142.0	78.4
Sale-leaseback deferral - recovered through June 2014 (Note 10 – Sale and Leaseback Transactions – Grand Gulf Lease Obligations)	22.3	74.6
Unamortized loss on reacquired debt - recovered over term of debt	21.5	25.0
Other	0.4	0.3
System Energy Total	$296.7	$290.0

(a)

The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana. As a result, a billing will occur monthly over the same term as the recovery and receipts will be submitted to Entergy Texas. Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable.

(b)

Does not earn a return on investment, but is offset by related liabilities.

Fuel and purchased power cost recovery

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2010 and 2009, that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2010	2009
	(In Millions)

Entergy Arkansas	$61.5	$122.8
Entergy Gulf States Louisiana (a)	$77.8	$57.8
Entergy Louisiana (a)	$8.8	$66.4
Entergy Mississippi	$3.2	($72.9)
Entergy New Orleans (a)	($2.8)	$8.1
Entergy Texas	($77.4)	($102.7)

(a)

2010 and 2009 include $100.1 million for Entergy Gulf States Louisiana, $68 million for Entergy Louisiana , and $4.1 million for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be over a period greater than twelve months.

Entergy Gulf States Louisiana made a $36.8 million adjustment to its deferred fuel costs in the fourth quarter 2009 relating to unrecovered nuclear fuel costs incurred since January 2008 that will now be recovered after a revision to the fuel adjustment clause methodology.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Arkansas

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.

Energy Cost Recovery Rider

Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.

In early October 2005, the APSC initiated an investigation into Entergy Arkansas's interim energy cost recovery rate. The investigation focused on Entergy Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006, the APSC extended its investigation to cover the costs included in Entergy Arkansas's March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.

In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas’s petition for rehearing and for stay of the APSC order.

In October 2008 Entergy Arkansas filed a motion to lift the stay and to rescind the APSC's January 2007 order in light of the arguments advanced in Entergy Arkansas’s rehearing petition and because the value for Entergy Arkansas’s customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. In December 2008, the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas’s rehearing request and of the unresolved issues in the proceeding. The APSC ordered the parties to submit their unresolved issues list in the pending proceeding, which the parties did. In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.

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Notes to Financial Statements

The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. Testimony has been filed and the APSC will now decide the case based on the record in the proceeding, including the prefiled testimony.

Entergy Gulf States Louisiana and Entergy Louisiana

Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the upcoming month based upon the level of such costs from the prior month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

In January 2003 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. The LPSC Staff issued its audit report in December 2010. The report recommends the disallowance of $23 million of costs which, with interest, will total $43 million. $2.3 million of this total relates to a realignment to and recovery through base rates of certain SO2 costs. Entergy Gulf States Louisiana filed comments disputing the findings in the report and requested a hearing. Entergy Gulf States Louisiana has recorded provisions for the estimated effect of this proceeding.

In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana's purchased gas adjustment clause filings for its gas distribution operations. The audit includes a review of the reasonableness of charges flowed through by Entergy Gulf States Louisiana for the period from 2003 through 2008. Discovery is in progress, but a procedural schedule has not been established.

In August 2000 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana. The time period that is the subject of the audit was January 1, 2000 through December 31, 2001. The scope of this docket was expanded to include a review of annual reports on fuel and purchased power transactions with affiliates and a prudence review of transmission planning issues and to include the years 2002 through 2004. Hearings were held and in May 2008 the ALJ issued a final recommendation that found in Entergy Louisiana’s favor on the issues, except for the disallowance of hypothetical SO2 allowance costs included in affiliate purchases. The ALJ recommended a refund of the SO2 allowance costs collected to date and a realignment of these costs into base rates prospectively with an amortization of the refunded amount through base rates over a five-year period. The LPSC issued an order in December 2008 affirming the ALJ’s recommendation. Entergy Louisiana recorded a provision for the disallowance, including interest, and refunded approximately $7 million to customers in 2009.

In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana's fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted quarterly to reflect accumulated over- or under-recoveries from the second prior quarter. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In October 2008 the MPSC issued an order directing Entergy Mississippi and Entergy Services, Inc. to provide documents associated with fuel adjustment clause litigation in Louisiana involving Entergy Louisiana and Entergy New Orleans, and in January 2009 issued an order requiring Entergy Mississippi to provide additional information related to the long-term Evangeline gas contract that had been an issue in the fuel adjustment clause litigation in Louisiana. Entergy Mississippi and Entergy Services filed a response to the MPSC order stating that gas from the Evangeline gas contract had been sold into the Entergy System exchange and had an effect on the costs paid by Entergy Mississippi’s customers. Further proceedings have not been scheduled.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Mississippi Attorney General Complaint

The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, Inc., and Entergy Power, Inc. alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The litigation is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. On December 29, 2008, the defendant Entergy companies filed to remove the attorney general’s suit to U.S. District Court (the forum that Entergy believes is appropriate to resolve the types of federal issues raised in the suit), where it is currently pending, and additionally answered the complaint and filed a counter-claim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. The Mississippi attorney general has filed a pleading seeking to remand the matter to state court. In May 2009, the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. In June 2006 the City Council authorized the recovery of all Grand Gulf costs through Entergy New Orleans’s fuel adjustment clause (a significant portion of Grand Gulf costs was previously recovered through base rates), and continued that authorization in approving the October 2006 formula rate plan filing settlement. Effective June 2009, the majority of Grand Gulf costs were realigned to base rates and are no longer flowed through the fuel adjustment clause.

Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.

In October 2007, Entergy Texas filed a request with the PUCT to refund $45.6 million, including interest, of fuel cost recovery over-collections through September 2007. In January 2008, Entergy Texas filed with the PUCT a stipulation and settlement agreement among the parties that updated the over-collection balance through November 2007 and established a refund amount, including interest, of $71 million. The PUCT approved the agreement in February 2008. The refund was made over a two-month period beginning February 2008, but was reduced by $10.3 million of under-recovered incremental purchased capacity costs.

In January 2008, Entergy Texas made a compliance filing with the PUCT describing how its 2007 rough production cost equalization receipts under the System Agreement were allocated between Entergy Gulf States, Inc.'s Texas and Louisiana jurisdictions. In December 2008 the PUCT adopted an ALJ proposal for decision recommending an additional $18.6 million allocation to Texas retail customers. Because the PUCT allocation to Texas retail

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

customers is inconsistent with the LPSC allocation to Louisiana retail customers, the PUCT's decision results in trapped costs between the Texas and Louisiana jurisdictions with no mechanism for recovery. Entergy Texas filed with the FERC a proposed amendment to the System Agreement bandwidth formula to specifically calculate the payments to Entergy Gulf States Louisiana and Entergy Texas of Entergy Gulf States, Inc.'s rough production cost equalization receipts for 2007. In May 2009 the FERC issued an order rejecting the proposed amendment. Because of the FERC's order, Entergy Texas recorded the effects of the PUCT's allocation of the additional $18.6 million to Texas retail customers in the second quarter 2009. On an after-tax basis, the charge to earnings was approximately $13.0 million (including interest). The PUCT and FERC decisions are now final.

In May 2009, Entergy Texas filed with the PUCT a request to refund $46.1 million, including interest, of fuel cost recovery over-collections through February 2009. Entergy Texas requested that the proposed refund be made over a four-month period beginning June 2009. Pursuant to a stipulation among the various parties, in June 2009 the PUCT issued an order approving a refund of $59.2 million, including interest, of fuel cost recovery overcollections through March 2009. The refund was made for most customers over a three-month period beginning July 2009.

In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Entergy Texas requested that the proposed refund be made over a six-month period beginning January 2010. Pursuant to a stipulation among the various parties, the PUCT issued an order approving a refund of $87.8 million, including interest, of fuel cost recovery overcollections through October 2009. The refund was made for most customers over a three-month period beginning January 2010.

In June 2010, Entergy Texas filed with the PUCT a request to refund approximately $66 million, including interest, of fuel cost recovery over-collections through May 2010. In September 2010 the PUCT issued an order providing for a $77 million refund for fuel cost recovery over-collections through June 2010. The refund was made for most customers over a three-month period beginning with the September 2010 billing cycle.

In December 2010, Entergy Texas filed with the PUCT a request to refund approximately $52 million, including interest, of fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved on an interim basis and is pending final action by the PUCT, Entergy Texas will refund over-collections of approximately $72.7 million through November 2010. The refund will be made for most customers over a three-month period beginning with the February 2011 billing cycle.

Entergy Texas’s December 2009 rate case filing, which is discussed below, also included a request to reconcile $1.8 billion of fuel and purchased power costs covering the period April 2007 through June 2009.

Storm Cost Recovery Filings with Retail Regulators

Entergy Arkansas

Entergy Arkansas January 2009 Ice Storm

In January 2009 a severe ice storm caused significant damage to Entergy Arkansas's transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. In June 2010 the APSC issued a financing order authorizing the issuance of approximately $126.3 million in storm cost recovery bonds, which includes carrying costs of $11.5 million and $4.6 million of up-front financing costs. See Note 5 to the financial statements for a discussion of the August 2010 issuance of the securitization bonds.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Gulf States Louisiana and Entergy Louisiana

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy's service territory. Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings). Entergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Act 55 financings, as discussed below. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Act 55 financing savings to customers via a Storm Cost Offset rider.

In December 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana, including carrying costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when the Act 55 financings are accomplished. In March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States Louisiana’s and Entergy Louisiana's proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $15.5 million and $27.75 million of customer benefits, respectively, through prospective annual rate reductions of $3.1 million and $5.55 million for five years. A stipulation hearing was held before the ALJ on April 13, 2010. On April 21, 2010, the LPSC approved the settlement and subsequently issued two financing orders and one ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financings.

In July 2010 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55. From the $462.4 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $262.4 million to acquire 2,624,297.11 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.

In July 2010 the LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana used $150.3 million to acquire 1,502,643.04 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy Gulf States Louisiana and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to large portions of the Utility’s service territories in Louisiana, Mississippi, and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area. The storms and flooding resulted in widespread power outages, significant damage to electric distribution, transmission, and generation and gas infrastructure, and the loss of sales and customers due to mandatory evacuations and the destruction of homes and businesses.

In March 2008, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed at the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Legislature (Act 55 financings). The Act 55 financings are expected to produce additional customer benefits as compared to traditional securitization. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a Storm Cost Offset rider. On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financings, approved requests for the Act 55 financings. On April 10, 2008, Entergy Gulf States Louisiana and Entergy Louisiana and the LPSC Staff filed with the LPSC an uncontested stipulated settlement that includes Entergy Gulf States Louisiana and Entergy Louisiana’s proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10 million and $30 million of customer benefits, respectively, through prospective annual rate reductions of $2 million and $6 million for five years. On April 16, 2008, the LPSC approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financings. In May 2008, the Louisiana State Bond Commission granted final approval of the Act 55 financings.

In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55. From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.

In August 2008 the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $187.7 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Gulf States Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.

Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LPFA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agent for the state.

Entergy New Orleans

In December 2005 the U.S. Congress passed the Katrina Relief Bill, a hurricane aid package that included Community Development Block Grant (CDBG) funding (for the states affected by Hurricanes Katrina, Rita, and Wilma) that allowed state and local leaders to fund individual recovery priorities. In March 2007 the City Council certified that Entergy New Orleans incurred $205 million in storm-related costs through December 2006 that are eligible for CDBG funding under the state action plan. Entergy New Orleans received $180.8 million of CDBG funds in 2007 and $19.2 million in 2010.

Entergy Texas

Hurricane Ike and Hurricane Gustav

Entergy Texas filed an application in April 2009 seeking a determination that $577.5 million of Hurricane Ike and Hurricane Gustav restoration costs are recoverable, including estimated costs for work to be completed. On August 5, 2009, Entergy Texas submitted to the ALJ an unopposed settlement agreement intended to resolve all issues in the storm cost recovery case. Under the terms of the agreement $566.4 million, plus carrying costs, are eligible for recovery. Insurance proceeds will be credited as an offset to the securitized amount. Of the $11.1 million difference between Entergy Texas’s request and the amount agreed to, which is part of the black box agreement and not directly attributable to any specific individual issues raised, $6.8 million is operation and maintenance expense for which Entergy Texas recorded a charge in the second quarter 2009. The remaining $4.3 million was recorded as utility plant. The PUCT approved the settlement in August 2009, and in September 2009 the PUCT approved recovery of the costs, plus carrying costs, by securitization. See Note 5 to the financial statements for a discussion of the November 2009 issuance of the securitization bonds.

Little Gypsy Repowering Project (Entergy and Entergy Louisiana)

In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC Staff and Intervenors filed testimony. The LPSC Staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it is probable that the Little Gypsy repowering project will be abandoned and accordingly reclassified the project costs from construction work in progress to a regulatory asset. This accounting reclassification does not modify Entergy Louisiana’s requested relief pending before the LPSC. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties conducted a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement is expected to be presented to the LPSC for approval in the first quarter 2011.

Retail Rate Proceedings

The following chart summarizes the Utility operating companies' current retail base rates:

Company	Authorized Return on Common Equity

Entergy Arkansas	10.2%	- Current retail base rates implemented in the July 2010 billing cycle pursuant to a settlement approved by the APSC.

Entergy Gulf States Louisiana	9.9%-11.4% Electric; 10.0%-11.0% Gas	- Current retail electric base rates implemented in the September 2010 billing cycle based on Entergy Gulf States Louisiana's revised 2009 test year formula rate plan filing approved by the LPSC. Current retail gas base rates reflect the rate stabilization plan filing for the 2009 test year ended September 2009.

Entergy Louisiana	9.45%- 11.05%	- Current retail base rates implemented in the September 2010 billing cycle based on Entergy Louisiana's revised 2009 test year formula rate plan filing approved by the LPSC.

Entergy Mississippi	10.79%- 13.05%	- Current retail base rates reflect Entergy Mississippi's latest formula rate plan filing, based on the 2009 test year, and a settlement approved by the MPSC.

Entergy New Orleans	10.7% - 11.5% Electric; 10.25% - 11.25% Gas	- Current retail base rates implemented in the October 2010 billing cycle pursuant to Entergy New Orleans's 2009 test year formula rate plan filing and a settlement approved by the City Council.

Entergy Texas	10.125%	- Current retail base rates implemented for usage beginning August 15, 2010, pursuant to a settlement of Entergy Texas's base rate case approved by the PUCT.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Filings with the APSC (Entergy Arkansas)

Retail Rates

2009 Base Rate Filing

In September 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. In June 2010 the APSC approved a settlement and subsequent compliance tariffs that provide for a $63.7 million rate increase, effective for bills rendered for the first billing cycle of July 2010. The settlement provides for a 10.2% return on common equity.

2006 Base Rate Filing

In August 2006, Entergy Arkansas filed with the APSC a request for a change in base rates. In June 2007, after hearings on the filing, the APSC ordered Entergy Arkansas to reduce its annual rates by $5 million, and set a return on common equity of 9.9% with a hypothetical common equity level lower than Entergy Arkansas’s actual capital structure. For the purpose of setting rates, the APSC disallowed a portion of costs associated with incentive compensation based on financial measures and all costs associated with Entergy’s stock-based compensation plans, and left Entergy Arkansas with no mechanism to recover $52 million of costs previously accumulated in Entergy Arkansas’s storm reserve and $18 million of removal costs associated with the termination of a lease. The base rate change was implemented effective for bills rendered after June 15, 2007.

Entergy Arkansas sought to overturn the APSC’s decision, but in December 2008 the Arkansas Court of Appeals upheld almost all aspects of the APSC decision. After considering the progress of the proceeding in light of the decision of the Court of Appeals, Entergy Arkansas recorded in the fourth quarter 2008 an approximately $70 million charge to earnings, on both a pre- and after-tax basis because these are primarily flow-through items, to recognize that the regulatory assets associated with the storm reserve costs, lease termination removal costs, and stock-based compensation were no longer probable of recovery. In April 2009 the Arkansas Supreme Court denied Entergy Arkansas’s petition for review of the Court of Appeals decision.

Filings with the LPSC

Formula Rate Plans (Entergy Gulf States Louisiana and Entergy Louisiana)

In March 2005 the LPSC approved a settlement proposal to resolve various dockets covering a range of issues for Entergy Gulf States Louisiana and Entergy Louisiana. The settlement included the establishment of a three-year formula rate plan for Entergy Gulf States Louisiana that, among other provisions, establishes a return on common equity mid-point of 10.65% for the initial three-year term of the plan and permits Entergy Gulf States Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed range of 9.9% to 11.4% are allocated 60% to customers and 40% to Entergy Gulf States Louisiana. Entergy Gulf States Louisiana made its initial formula rate plan filing in June 2005. The formula rate plan was subsequently extended one year.

Entergy Louisiana made a rate filing with the LPSC requesting a base rate increase in January 2004. In May 2005 the LPSC approved a settlement that included the adoption of a three-year formula rate plan, the terms of which included an ROE mid-point of 10.25% for the initial three-year term of the plan and permit Entergy Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed regulatory range of 9.45% to 11.05% will be allocated 60% to customers and 40% to Entergy Louisiana. The initial formula rate plan filing was made in May 2006.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

As discussed below the formula rate plans for Entergy Gulf States Louisiana and Entergy Louisiana have been extended, with return on common equity provisions consistent with previously approved provisions, to cover the 2008, 2009, and 2010 test years.

Retail Rates - Electric

(Entergy Gulf States Louisiana)

In October 2009 the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.

In May 2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.

(Entergy Louisiana)

In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).

Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC accepted the joint report.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

In May 2010, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.

Retail Rates - Gas (Entergy Gulf States Louisiana)

In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. The sixty-day review and comment period for this filing remains open.

In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi's return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi's request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi will continue to use a historical test year for its annual evaluation reports under the plan.

In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the new formula rate plan rider. In June 2010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates, but does provide for the deferral as a regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Filings with the City Council (Entergy New Orleans)

Formula Rate Plans and Storm-related Riders

On July 31, 2008, Entergy New Orleans filed an electric and gas base rate case with the City Council. On April 2, 2009, the City Council approved a comprehensive settlement. The settlement provided for a net $35.3 million reduction in combined fuel and non-fuel electric revenue requirement, including conversion of a $10.6 million voluntary recovery credit, implemented in January 2008, to a permanent reduction and substantial realignment of Grand Gulf cost recovery from fuel to electric base rates, and a $4.95 million gas base rate increase, both effective June 1, 2009, with adjustment of the customer charges for all rate classes. A new three-year formula rate plan was also adopted, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans is over- or under-earning. The formula rate plan also includes a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.

In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council's Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.

The 2008 rate case settlement also included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs.

In June 2006, Entergy New Orleans made its annual formula rate plan filings with the City Council. The filings presented various alternatives to reflect the effect of Entergy New Orleans’s lost customers and decreased revenue following Hurricane Katrina. The alternative that Entergy New Orleans recommended adjusts for lost customers and assumes that the City Council’s June 2006 decision to allow recovery of all Grand Gulf costs through the fuel adjustment clause stays in place during the rate-effective period (a significant portion of Grand Gulf costs was previously recovered through base rates).

At the same time as it made its formula rate plan filings, Entergy New Orleans also filed with the City Council a request to implement two storm-related riders. With the first rider, Entergy New Orleans sought to recover the electric and gas restoration costs that it had actually spent through March 31, 2006. Entergy New Orleans also proposed semiannual filings to update the rider for additional restoration spending and also to consider the receipt of CDBG funds or insurance proceeds that it may receive. With the second rider, Entergy New Orleans sought to establish a storm reserve to provide for the risk of another storm.

In October 2006, the City Council approved a settlement agreement that resolved Entergy New Orleans’s rate and storm-related rider filings by providing for phased-in rate increases, while taking into account with respect to storm restoration costs the anticipated receipt of CDBG funding as recommended by the Louisiana Recovery Authority. The settlement provided for a 0% increase in electric base rates through December 2007, with a $3.9 million increase implemented in January 2008. Recovery of all Grand Gulf costs through the fuel adjustment clause was continued. Gas base rates increased by $4.75 million in November 2006 and increased by an additional $1.5 million in March 2007 and an additional $4.75 million in November 2007. The settlement called for Entergy New Orleans to file a base rate case by July 31, 2008, which it did as discussed above. The settlement agreement discontinued the formula rate plan and the generation performance-based plan but permitted Entergy New Orleans to file an application to seek authority to implement formula rate plan mechanisms no sooner than six months following the effective date of the implementation of the base rates resulting from the July 31, 2008 base rate case. The settlement also authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider beginning in March 2007. These storm reserve funds will be held in a restricted escrow account.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The rate case also includes a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.

The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provides for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulates an authorized return on equity of 10.125%. Baseline values were established to be used in Entergy Texas's request for a transmission cost recovery factor that will be made in a separate proceeding. The settlement states that Entergy Texas's fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also sets River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.

System Agreement Cost Equalization Proceedings

In June 2005, the FERC issued a decision in the System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:

·	The System Agreement no longer roughly equalizes total production costs among the Utility operating companies.

·	In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs.

In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.

·	The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.

Assessing the potential effects of the FERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas’s total production costs are below the Entergy System average production costs.

The LPSC, APSC, MPSC, and the AEEC appealed the FERC’s decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit affirmed the FERC’s decision in most respects, but remanded the case to the FERC for further proceedings and reconsideration of its conclusion that it was prohibited from ordering refunds and its determination to implement the bandwidth remedy commencing with calendar year 2006 production costs (with the first payments/receipts commencing in June 2007), rather than commencing the remedy on June 1, 2005. The D.C. Circuit concluded the FERC had failed so far in the proceeding to offer a reasoned explanation regarding these issues. As discussed below, in December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. The FERC also deferred further action on the question of whether it provided sufficient rationale for not ordering refunds, and whether it impermissibly delayed implementation of the bandwidth remedy, until resolution of this paper hearing.

In April 2006, the Utility operating companies filed with the FERC their compliance filing to implement the provisions of the FERC’s decision. The filing amended the System Agreement to provide for the calculation of production costs, average production costs, and payments/receipts among the Utility operating companies to the extent required to maintain rough production cost equalization pursuant to the FERC’s decision. The FERC accepted the compliance filing in November 2006, with limited modifications. Provisions of the compliance filing as approved by the FERC include: the first payments commenced in June 2007, rather than earlier; interest is not required on the unpaid balance; and any payments will be made over seven months, rather than 12. In April 2007, the FERC denied various requests for rehearing, with one exception regarding the issue of retrospective refunds. That issue will be addressed subsequent to the remanded proceeding involving the interruptible load decision discussed further below in this section under “Interruptible Load Proceeding.”

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Calendar Year 2010 Production Costs

The liabilities and assets for the preliminary estimate of the payments and receipts required to implement the FERC’s remedy based on calendar year 2010 production costs were recorded in December 2010, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2011.

	Payments or (Receipts)
	(In Millions)

Entergy Arkansas	$52
Entergy Gulf States Louisiana	$-
Entergy Louisiana	$-
Entergy Mississippi	($37)
Entergy New Orleans	($15)
Entergy Texas	$-

The actual payments/receipts for 2011, based on calendar year 2010 production costs, will not be calculated until the Utility operating companies’ FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.

Rough Production Cost Equalization Rates

Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:

	2007 Payments or (Receipts) Based on 2006 Costs	2008 Payments or (Receipts) Based on 2007 Costs	2009 Payments or (Receipts) Based on 2008 Costs	2010 Payments or (Receipts) Based on 2009 Costs
	(In Millions)

Entergy Arkansas	$252	$252	$390	$41
Entergy Gulf States Louisiana	($120)	($124)	($107)	$-
Entergy Louisiana	($91)	($36)	($140)	($22)
Entergy Mississippi	($41)	($20)	($24)	($19)
Entergy New Orleans	$-	($7)	$-	$-
Entergy Texas	($30)	($65)	($119)	$-

The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “Fuel and purchased power cost recovery, Entergy Texas,” above for discussion of a PUCT decision that resulted in $18.6 million of trapped costs between Entergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in $14.5 million of trapped costs at Entergy Arkansas.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Based on the FERC’s April 27, 2007 order on rehearing that is discussed above, in the second quarter 2007 Entergy Arkansas recorded accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas recorded accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy based on calendar year 2006 production costs. Entergy Arkansas recorded a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas recorded corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The companies have followed this same accounting practice each year since then. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.

2007 Rate Filing Based on Calendar Year 2006 Production Costs

Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concludes, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.

AmerenUE argued that its current wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. According to AmerenUE, Entergy Arkansas has sought to collect from AmerenUE approximately $14.5 million of the 2007 Entergy Arkansas bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds of this amount, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.

2008 Rate Filing Based on Calendar Year 2007 Production Costs

Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.

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Notes to Financial Statements

The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. Entergy, the APSC, the LPSC, and the MPSC have submitted briefs on exceptions in the proceeding, and the matter has been submitted to the FERC for decision.

2009 Rate Filing Based on Calendar Year 2008 Production Costs

Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy have submitted briefs on exceptions in the proceeding.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC's orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011, with an initial decision scheduled for July 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. Briefing on the issue concluded on February 14, 2011. A hearing on the show cause order is scheduled for March 3, 2011.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion, the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC's orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. Because of its refund obligation to its customers as a result of this proceeding and a related LPSC proceeding, Entergy Louisiana recorded provisions during 2008 of approximately $16 million, including interest, for rate refunds. The refunds were made in the fourth quarter 2009.

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Notes to Financial Statements

Following the filing of petitioners' initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC's decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC's unopposed motion on June 24, 2009, and directed the FERC to file status reports at 60-day intervals beginning August 24, 2009. The D.C. Circuit also directed the parties to file motions to govern future proceedings in the case within 30 days of the completion of the FERC proceedings. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy have requested rehearing of the FERC's decision. In September 2010, the FERC set for hearing and settlement judge procedures the Utility operating companies' calculation of the refunds for the 15-month refund period of May 14, 1995 through August 13, 1996, as contained in the November 2007 refund report. The purpose of the hearing is to determine whether the refund amounts for such period were calculated in a just and reasonable manner. The settlement proceedings are ongoing.

Entergy Arkansas filed a request with the APSC for recovery of the refund paid to its customers and the APSC staff has filed a motion to dismiss the request. A procedural schedule has not been set in the proceeding.

Entergy Arkansas Opportunity Sales Proceeding

In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explains that the FERC already has determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion. On December 7, 2009, the FERC issued an order setting the matter for hearing and settlement procedures.

The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers of $144 million and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills, which has not occurred. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.

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Notes to Financial Statements

In December 2010 the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy Corporation, or an Entergy Corporation subsidiary, is the shareholder of each of the Utility operating companies. Entergy disagrees with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision. FERC consideration of the initial decision is pending. Entergy is unable to estimate the potential damages in this matter because certain aspects of how the refunds would be calculated require clarification by the FERC.

LPSC Interruptible Load Proceeding (Entergy Louisiana)

As discussed above, the FERC issued orders in September 2005 and 2007 in which it directed Entergy to remove all interruptible load from certain computations of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, in September 2008 the FERC directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In October 2009 the LPSC issued an order approving the flow through to retail rates of the LPSC-jurisdictional portion of the payments and credits resulting from the FERC’s orders that had not yet been flowed through to retail rates, which required a net refund to Entergy Louisiana retail customers of $17.6 million, including interest. The refunds were made in the fourth quarter 2009. Of this amount, $5.4 million was refunded subject to adjustment in the event that future action by the FERC or the D.C. Circuit Court of Appeals results in a reversal or change in the amount of the refunds ordered by the FERC in September 2008.

NOTE 4. REVOLVING CREDIT FACILITIES, LINES OF CREDIT AND SHORT-TERM BORROWINGS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Entergy Corporation has a revolving credit facility that expires in August 2012 and has a borrowing capacity of $3.5 billion. Entergy Corporation also has the ability to issue letters of credit against the total borrowing capacity of the credit facility. The facility fee is currently 0.125% of the commitment amount. Facility fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 2010 was 0.78% on the drawn portion of the facility. Following is a summary of the borrowings outstanding and capacity available under the facility as of December 31, 2010.

Capacity	Borrowings	Letters of Credit	Capacity Available
(In Millions)

$3,466	$1,632	$25	$1,809

Entergy Corporation’s facility requires it to maintain a consolidated debt ratio of 65% or less of its total capitalization. Entergy is in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the facility maturity date may occur.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas each had credit facilities available as of December 31, 2010 as follows:

Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of December 31, 2010

Entergy Arkansas	April 2011	$75.125 million (b)	2.75%	-
Entergy Gulf States Louisiana	August 2012	$100 million (c)	0.67%	-
Entergy Louisiana	August 2012	$200 million (d)	0.67%	-
Entergy Mississippi	May 2011	$35 million (e)	2.01%	-
Entergy Mississippi	May 2011	$25 million (e)	2.01%	-
Entergy Mississippi	May 2011	$10 million (e)	2.01%	-
Entergy Texas	August 2012	$100 million (f)	0.74%	-

(a)	The interest rate is the weighted average interest rate as of December 31, 2010 applied, or that would be applied, to outstanding borrowings under the facility.
(b)	The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization. Borrowings under the Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable.
(c)	The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against the borrowing capacity of the facility. As of December 31, 2010, no letters of credit were outstanding. The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(d)	The credit facility allows Entergy Louisiana to issue letters of credit against the borrowing capacity of the facility. As of December 31, 2010, no letters of credit were outstanding. The credit facility requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization.

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Notes to Financial Statements

(e)

Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable. Entergy Mississippi is required to maintain a consolidated debt ratio of 65% or less of its total capitalization.

(f)

The credit facility allows Entergy Texas to issue letters of credit against the borrowing capacity of the facility. As of December 31, 2010, no letters of credit were outstanding. The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization. Pursuant to the terms of the credit agreement securitization bonds are excluded from debt and capitalization in calculating the debt ratio.

The facility fees on the credit facilities range from 0.09% to 0.15% of the commitment amount.

The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. The current FERC-authorized limits are effective through October 31, 2011 under a FERC order dated October 14, 2009. In addition to borrowings from commercial banks, these companies are authorized under a FERC order to borrow from the Entergy System money pool. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized limits. The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 2010 (aggregating both money pool and external short-term borrowings) for the Registrant Subsidiaries:

	Authorized	Borrowings
	(In Millions)
Entergy Arkansas	$250	-
Entergy Gulf States Louisiana	$200	-
Entergy Louisiana	$250	-
Entergy Mississippi	$175	$33
Entergy New Orleans	$100	-
Entergy Texas	$200	-
System Energy	$200	-

Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)

See Note 18 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIE) effective in the first quarter 2010. The variable interest entities have credit facilities and also issue commercial paper to finance the acquisition and ownership of nuclear fuel as follows as of December 31, 2010:

Company	Expiration Date	Amount of Facility	Weighted Average Interest Rate on Borrowings (a)	Amount Outstanding as of December 31, 2010
	(Dollars in Millions)

Entergy Arkansas VIE	July 2013	$85	2.45%	$62.8
Entergy Gulf States Louisiana VIE	July 2013	$85	2.125%	$24.2
Entergy Louisiana VIE	July 2013	$90	2.42%	$23.1
System Energy VIE	July 2013	$100	2.40%	$38.3

(a)	Includes letter of credit fees and bank fronting fees on commercial paper issuances by the VIEs for Entergy Arkansas, Entergy Louisiana, and System Energy. The VIE for Entergy Gulf States Louisiana does not issue commercial paper, but borrows directly on its bank credit facility.

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Notes to Financial Statements

The amount outstanding on the Entergy Gulf States Louisiana credit facility is included in long-term debt on its balance sheet and the commercial paper outstanding for the other VIEs is classified as a current liability on the respective balance sheets. The commitment fees on the credit facilities are 0.20% of the commitment amount. Each credit facility requires the respective lessee (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or Entergy Corporation as Guarantor for System Energy) to maintain a consolidated debt ratio of 70% or less of its total capitalization.

The variable interest entities had long-term notes payable that are included in long-term debt on the respective balance sheets as of December 31, 2010 as follows:

Company	Description	Amount

Entergy Arkansas VIE	5.60% Series G due September 2011	$35 million
Entergy Arkansas VIE	9% Series H due June 2013	$30 million
Entergy Arkansas VIE	5.69% Series I due July 2014	$70 million
Entergy Gulf States Louisiana VIE	5.56% Series N due May 2013	$75 million
Entergy Gulf States Louisiana VIE	5.41% Series O due July 2012	$60 million
Entergy Louisiana VIE	5.69% Series E due July 2014	$50 million
System Energy VIE	6.29% Series F due September 2013	$70 million
System Energy VIE	5.33% Series G due April 2015	$60 million

In accordance with regulatory treatment, interest on the nuclear fuel company variable interest entities’ credit facilities, commercial paper, and long-term notes payable is included as fuel expense.

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Notes to Financial Statements

NOTE 5. LONG - TERM DEBT (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2010 and 2009 consisted of:

Type of Debt and Maturity	Weighted Average Interest Rate December 31, 2010	Interest Rate Ranges at December 31,		Outstanding at December 31,
Type of Debt and Maturity	Weighted Average Interest Rate December 31, 2010	2010	2009	2010	2009
				(In Thousands)

Mortgage Bonds
2010-2015	4.68%	3.6%-6.2%	4.5%-6.2%	$820,000	$1,662,120
2016-2020	5.98%	3.95%-7.125%	4.95%-7.125%	1,910,000	1,910,000
2021-2025	5.13%	3.75%-5.66%	5.40%-5.66%	1,258,738	909,097
2026-2035	5.90%	4.44%-6.4%	5.65%-7.6%	1,118,546	1,318,950
2039-2041	6.28%	5.75%-7.875%	7.875%	755,000	150,000

Governmental Bonds (a)
2010-2015	4.26%	2.875%-6.75%	5.45%-7.0%	79,295	91,310
2016-2020	4.76%	4.6%-5.8%	4.6%-6.3%	65,540	214,200
2021-2025	5.67%	4.6%-5.9%	4.6%-5.9%	410,005	410,005
2026-2030	5.32%	5.0%-6.2%	6.2%-6.6%	288,680	111,680

Securitization Bonds
2013-2020	3.93%	2.12%-5.79%	2.12%-5.79%	474,318	505,628
2021-2023	4.25%	2.30%-5.93%	4.38%-5.93%	457,100	333,000

Variable Interest Entities Notes Payable (Note 4)
2011-2015	5.69%	2.125%-9%	-	474,200	-

Entergy Corporation Notes
due May 2010	-	-	6.58%	-	75,000
due November 2010	-	-	6.9%	-	140,000
due March 2011	n/a	7.06%	7.06%	86,000	86,000
due September 2015	n/a	3.625%	-	550,000	-
due September 2020	n/a	5.125%	-	450,000	-

Note Payable to NYPA	(b)	(b)	(b)	155,971	177,543
5 Year Credit Facility (Note 4)	n/a	0.78%	1.377%	1,632,120	2,566,150
Entergy Corporation Bank Term Loan due 2010	-	-	1.41%	-	60,000
Long-term DOE Obligation (c)	-	-	-	180,919	180,683
Waterford 3 Lease Obligation (d)	n/a	7.45%	7.45%	223,802	241,128
Grand Gulf Lease Obligation (d)	n/a	5.13%	5.13%	222,280	266,864
Unamortized Premium and Discount - Net				(10,181)	(10,635)
Other				14,372	18,972
Total Long-Term Debt				11,616,705	11,417,695
Less Amount Due Within One Year				299,548	711,957
Long-Term Debt Excluding Amount Due Within One Year				$11,317,157	$10,705,738

Fair Value of Long-Term Debt (e)				$10,988,646	$10,727,908

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Notes to Financial Statements

(a)	Consists of pollution control revenue bonds and environmental revenue bonds.
(b)	These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%.
(c)	Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.
(d)	See Note 10 for further discussion of the Waterford 3 and Grand Gulf Lease Obligations.
(e)	The fair value excludes lease obligations of $224 million at Entergy Louisiana and $222 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $156 million at Entergy, and includes debt due within one year. Fair values are based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2010, for the next five years are as follows:

	Amount
	(In Thousands)

2011	$230,257
2012	$1,815,972
2013	$734,309
2014	$150,681
2015	$863,539

In November 2000, Entergy’s non-utility nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. Entergy issued notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing. These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. In accordance with the purchase agreement with NYPA, the purchase of Indian Point 2 in 2001 resulted in Entergy becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September 2003. This liability was recorded upon the purchase of Indian Point 2 in September 2001, and is included in the note payable to NYPA balance above. In July 2003, a payment of $102 million was made prior to maturity on the note payable to NYPA. Under a provision in a letter of credit supporting these notes, if certain of the Utility operating companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit.

One of the covenants in certain of the Entergy Corporation notes require it to maintain a consolidated debt ratio of 65% or less of its total capitalization. If Entergy’s debt ratio exceeds this limit, or if Entergy Corporation or certain of the Utility operating companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the notes’ maturity dates may occur.

Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through July 2011. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2012. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2012.

Capital Funds Agreement

Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:

100

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Notes to Financial Statements

·	maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);

·	permit the continued commercial operation of Grand Gulf;

·	pay in full all System Energy indebtedness for borrowed money when due; and

·	enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.

Long-term debt for the Registrant Subsidiaries as of December 31, 2010 and 2009 consisted of:

	2010	2009
	(In Thousands)
Entergy Arkansas
Mortgage Bonds:
4.50% Series due June 2010	$-	$100,000
5.40% Series due August 2013	300,000	300,000
5.4% Series due May 2018	-	150,000
5.0% Series due July 2018	115,000	115,000
3.75% Series due February 2021	350,000	-
5.66% Series due February 2025	175,000	175,000
6.7% Series due April 2032	-	100,000
6.0% Series due November 2032	-	100,000
5.9% Series due June 2033	100,000	100,000
6.38% Series due November 2034	60,000	60,000
5.75% Series due November 2040	225,000	-
Total mortgage bonds	1,325,000	1,200,000

Governmental Bonds (a):
6.3% Series due 2016, Pope County (d)	-	19,500
4.6% Series due 2017, Jefferson County (d)	54,700	54,700
6.3% Series due 2020, Pope County	-	120,000
5.0% Series due 2021, Independence County (d)	45,000	45,000
Total governmental bonds	99,700	239,200

Variable Interest Entity Notes Payable (Note 4)
5.60% Series G due September 2011	35,000	-
9% Series H due June 2013	30,000	-
5.69% Series I due July 2014	70,000	-
Total variable interest entity notes payable	135,000	-

Securitization Bonds
2.30% Series Senior Secured due August 2021	124,100	-
Total securitization bonds	124,100	-

Other
Long-term DOE Obligation (b)	180,919	180,683
Unamortized Premium and Discount – Net	(812)	(1,314)
Other	3	-

Total Long-Term Debt	1,863,910	1,618,569
Less Amount Due Within One Year	35,000	100,000
Long-Term Debt Excluding Amount Due Within One Year	$1,828,910	$1,518,569

Fair Value of Long-Term Debt (c)	$1,712,663	$1,463,378

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	2010	2009
	(In Thousands)
Entergy Gulf States Louisiana (e)
Mortgage Bonds:
4.875% Series due November 2011	$-	$200,000
5.70% Series due June 2015	-	200,000
5.25% Series due August 2015	-	92,120
6.00% Series due May 2018	375,000	375,000
3.95% Series due October 2020	250,000	-
5.59% Series due October 2024	300,000	300,000
6.2% Series due July 2033	240,000	240,000
6.18% Series due March 2035	85,000	85,000
Total mortgage bonds	1,250,000	1,492,120

Governmental Bonds (a):
5.45% Series due 2010, Calcasieu Parish	-	11,975
6.75% Series due 2012, Calcasieu Parish	26,170	26,170
6.7% Series due 2013, Pointe Coupee Parish	9,460	9,460
5.7% Series due 2014, Iberville Parish	11,710	11,710
5.8% Series due 2015, West Feliciana Parish	-	15,395
7.0% Series due 2015, West Feliciana Parish	-	16,600
2.875% Series due 2015, Louisiana Public Facilities Authority (d)	31,955	-
5.8% Series due 2016, West Feliciana Parish	10,840	20,000
5.0% Series due 2028, Louisiana Public Facilities Authority (d)	83,680	-
6.6% Series due 2028, West Feliciana Parish	-	21,680
Total governmental bonds	173,815	132,990

Variable Interest Entity Notes Payable
5.41% Series O due July 2012	60,000	-
5.56% Series N due May 2013	75,000	-
Credit Facility due July 2013, weighted avg rate 2.125%	24,200	-
Total variable interest entity notes payable	159,200	-

Other
Unamortized Premium and Discount - Net	(2,287)	(2,372)
Other	3,604	3,603

Total Long-Term Debt	1,584,332	1,626,341
Less Amount Due Within One Year	-	11,975
Long-Term Debt Excluding Amount Due Within One Year	$1,584,332	$1,614,366

Fair Value of Long-Term Debt (c)	$1,643,514	$1,637,862

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Notes to Financial Statements

	2010	2009
	(In Thousands)
Entergy Louisiana
Mortgage Bonds:
4.67% Series due June 2010	$-	$55,000
5.83% Series due November 2010	-	150,000
5.09% Series due November 2014	-	115,000
5.56% Series due September 2015	-	100,000
6.50% Series due September 2018	300,000	300,000
5.5% Series due April 2019	-	100,000
5.40% Series due November 2024	400,000	400,000
4.44% Series due January 2026	250,000	-
7.6% Series due April 2032	-	150,000
6.4% Series due October 2034	70,000	70,000
6.3% Series due September 2035	100,000	100,000
6.0% Series due March 2040	150,000	-
5.875% Series due June 2041	150,000	-
Total mortgage bonds	1,420,000	1,540,000

Governmental Bonds (a):
5.0% Series due 2030, Louisiana Public Facilities Authority (d)	115,000	-
Total governmental bonds	115,000	-

Variable Interest Entity Notes Payable
5.69% Series E due July 2014	50,000	-
Total variable interest entity notes payable	50,000	-

Other Long-Term Debt
Waterford 3 Lease Obligation 7.45% (Note 10)	223,802	241,128
Unamortized Premium and Discount - Net	(1,689)	(1,576)
Other	3	-

Total Long-Term Debt	1,807,116	1,779,552
Less Amount Due Within One Year	35,550	222,326
Long-Term Debt Excluding Amount Due Within One Year	$1,771,566	$1,557,226

Fair Value of Long-Term Debt (c)	$1,515,121	$1,565,969

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Notes to Financial Statements

	2010	2009
	(In Thousands)
Entergy Mississippi
Mortgage Bonds:
4.65% Series due May 2011	$80,000	$80,000
5.15% Series due February 2013	100,000	100,000
5.92% Series due February 2016	100,000	100,000
4.95% Series due June 2018	95,000	95,000
6.64% Series due July 2019	150,000	150,000
6.0% Series due November 2032	75,000	75,000
7.25% Series due December 2032	-	100,000
6.25% Series due April 2034	100,000	100,000
6.20% Series due April 2040	80,000	-
Total mortgage bonds	780,000	800,000

Governmental Bonds (a):
4.60% Series due 2022, Mississippi Business Finance Corp.(d)	16,030	16,030
4.90% Series due 2022, Independence County (d)	30,000	30,000
Total governmental bonds	46,030	46,030

Other
Unamortized Premium and Discount - Net	(652)	(726)

Total Long-Term Debt	825,378	845,304
Less Amount Due Within One Year	80,000	-
Long-Term Debt Excluding Amount Due Within One Year	$745,378	$845,304

Fair Value of Long-Term Debt (c)	$802,045	$874,131

	2010	2009
	(In Thousands)
Entergy New Orleans
Mortgage Bonds:
4.98% Series due July 2010	$-	$30,000
5.25% Series due August 2013	70,000	70,000
6.75% Series due October 2017	-	25,000
5.10% Series due December 2020	25,000	-
5.6% Series due September 2024	33,738	34,097
5.65% Series due September 2029	38,546	38,950
Total mortgage bonds	167,284	198,047

Other Long-Term Debt
Affiliate Notes Payable (f)	-	74,230
Unamortized Premium and Discount - Net	(69)	(24)

Total Long-Term Debt	167,215	272,253
Less Amount Due Within One Year	-	104,230
Long-Term Debt Excluding Amount Due Within One Year	$167,215	$168,023

Fair Value of Long-Term Debt (c)	$171,077	$198,062

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Notes to Financial Statements

Entergy Texas

Entergy Gulf States Louisiana was primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed its pro rata share of this long-term debt, which was $1.079 billion, or approximately 46%, of which none remains outstanding at December 31, 2010. The pro rata share of the long-term debt assumed by Entergy Texas was determined by first determining the net assets for each company on a book value basis, and then calculating a debt assumption ratio that resulted in the common equity ratios for each company being approximately the same as the Entergy Gulf States, Inc. common equity ratio immediately prior to the jurisdictional separation. By June 2010, Entergy Texas had repaid the outstanding assumed debt and the debt assumption agreement was terminated.

	2010	2009
	(In Thousands)
Mortgage Bonds share assumed under debt assumption agreement:
4.875% Series due November 2011	$-	$28,023
5.70% Series due June 2015	-	91,592
6.18% Series due March 2035	-	38,927
Total mortgage bonds	-	158,542

Governmental Bonds share assumed under debt assumption agreement (a):
7.0% Series due 2015, West Feliciana Parish	-	40
5.8% Series due 2016, West Feliciana Parish	-	9,160
Total governmental bonds	-	9,200

Mortgage Bonds:
3.60% Series due June 2015	200,000	-
7.125% Series due February 2019	500,000	500,000
7.875% Series due June 2039	150,000	150,000
Total mortgage bonds	850,000	650,000

Securitization Bonds
5.51% Series Senior Secured, Series A due October 2013	38,152	56,728
5.79% Series Senior Secured, Series A due October 2018	121,600	121,600
5.93% Series Senior Secured, Series A due June 2022	114,400	114,400
2.12% Series Senior Secured due February 2016	169,766	182,500
3.65% Series Senior Secured due August 2019	144,800	144,800
4.38% Series Senior Secured due November 2023	218,600	218,600
Total securitization bonds	807,318	838,628

Other
Unamortized Premium and Discount - Net	(3,419)	(3,759)
Other	5,331	5,414

Total Long-Term Debt	1,659,230	1,658,025
Less Amount Due Within One Year	-	167,742
Long-Term Debt Excluding Amount Due Within One Year	$1,659,230	$1,490,283

Fair Value of Long-Term Debt (c)	$1,822,219	$1,747,348

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Notes to Financial Statements

	2010	2009
	(In Thousands)
System Energy
Mortgage Bonds:
6.2% Series due October 2012	$70,000	$70,000
Total mortgage bonds	70,000	70,000

Governmental Bonds (a):
5.875% Series due 2022, Mississippi Business Finance Corp.	216,000	216,000
5.9% Series due 2022, Mississippi Business Finance Corp.	102,975	102,975
6.2% Series due 2026, Claiborne County	90,000	90,000
Total governmental bonds	408,975	408,975

Variable Interest Entity Notes Payable
6.29% Series F due September 2013	70,000	-
5.33% Series G due April 2015	60,000	-
Total variable interest entity notes payable	130,000	-

Other Long-Term Debt:
Grand Gulf Lease Obligation 5.13% (Note 10)	222,280	266,864
Unamortized Premium and Discount - Net	(789)	(864)
Other	2	-

Total Long-Term Debt	830,468	744,975
Less Amount Due Within One Year	33,740	41,715
Long-Term Debt Excluding Amount Due Within One Year	$796,728	$703,260

Fair Value of Long-Term Debt (c)	$611,837	$479,893

(a)	Consists of pollution control revenue bonds and environmental revenue bonds.
(b)	Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.
(c)	The fair value excludes lease obligations of $224 million at Entergy Louisiana and $222 million at System Energy and long-term DOE obligations of $181 million at Entergy Arkansas, and includes debt due within one year. Fair values are based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.
(d)	The bonds are secured by a series of collateral first mortgage bonds.
(e)	Entergy Gulf States Louisiana was primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed approximately 46% of this long-term debt. Entergy Gulf States Louisiana recorded an assumption asset on its balance sheet to reflect the long-term debt assumed by Entergy Texas. By June 2010, Entergy Texas had repaid the outstanding assumed debt and the debt assumption agreement was terminated.
(f)	The affiliate note payable at Entergy New Orleans that was due May 2010 was classified as current notes payable - associated companies in 2009.

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Notes to Financial Statements

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2010, for the next five years are as follows:

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy

2011	$35,000	-	-	$80,000	-	-	-
2012	-	$86,170	-	-	-	-	$70,000
2013	$330,000	$108,660	-	$100,000	$70,000	$38,152	$70,000
2014	$70,000	$11,710	$50,000	-	-	-	-
2015	-	$31,955	-	-	-	$200,000	$60,000

Entergy Arkansas Securitization Bonds

In June 2010 the APSC issued a financing order authorizing the issuance of bonds to recover Entergy Arkansas’s January 2009 ice storm damage restoration costs, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. The bonds have a coupon of 2.30% and an expected maturity date of August 2021. Although the principal amount is not due until the date given above, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $10.3 million for 2011, $12.2 million for 2012, $12.6 million for 2013, $12.8 million for 2014, and $13.2 million for 2015. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections.

Entergy Texas Securitization Bonds - Hurricane Rita

In April 2007 the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $353 million of Entergy Texas’s Hurricane Rita reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $329.5 million of senior secured transition bonds (securitization bonds) as follows:

	Amount
	(In Thousands)
Senior Secured Transition Bonds, Series A:
Tranche A-1 (5.51%) due October 2013	$93,500
Tranche A-2 (5.79%) due October 2018	121,600
Tranche A-3 (5.93%) due June 2022	114,400
Total senior secured transition bonds	$329,500

Although the principal amount of each tranche is not due until the dates given above, Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds over the next five years in the amounts of $19.7 million for 2011, $20.8 million for 2012, $21.9 million for 2013, $23.2 million for 2014, and $24.6 million for 2015. All of the scheduled principal payments for 2011-2012 are for Tranche A-1, except for $2.3 million for Tranche A-2 in 2012, and all of the scheduled principal payments for 2013-2015 are for Tranche A-2.

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Notes to Financial Statements

With the proceeds, Entergy Gulf States Reconstruction Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.

Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav

In September 2009 the PUCT authorized the issuance of securitization bonds to recover $566.4 million of Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction costs, offset by insurance proceeds. In November 2009, Entergy Texas Restoration funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds), as follows:

	Amount
	(In Thousands)
Senior Secured Transition Bonds
Tranche A-1 (2.12%) due February 2016	$182,500
Tranche A-2 (3.65%) due August 2019	144,800
Tranche A-3 (4.38%) due November 2023	218,600
Total senior secured transition bonds	$545,900

Although the principal amount of each tranche is not due until the dates given above, Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $37.8 million for 2011, $38.6 million for 2012, $39.4 million for 2013, $40.2 million for 2014, and $41.2 million for 2015. All of the expected principal payments for 2011-2014 are for Tranche A-1 and $13.8 million of the scheduled principal payments for 2015 are for Tranche A-1 and $27.4 million are for Tranche A-2.

With the proceeds, Entergy Texas Restoration Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Texas Restoration Funding, including the transition property, and the creditors of Entergy Texas Restoration Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Texas Restoration Funding except to remit transition charge collections.

Entergy Texas Note Payable to Entergy Corporation

In December 2008, Entergy Texas borrowed $160 million from its parent company, Entergy Corporation, under a $300 million revolving credit facility pursuant to an Inter-Company Credit Agreement between Entergy Corporation and Entergy Texas. The note had a December 3, 2013 maturity date. Entergy Texas used the proceeds, together with other available corporate funds, to pay at maturity the portion of the $350 million Floating Rate series of First Mortgage Bonds due December 2008 that had been assumed by Entergy Texas, and that bond series is no longer outstanding. In January 2009, Entergy Texas repaid its $160 million note payable to Entergy Corporation with the proceeds from the issuance of $500 million of 7.125% Series mortgage bonds in January 2009.

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Notes to Financial Statements

Entergy New Orleans Affiliate Notes

Pursuant to its plan of reorganization, in May 2007 Entergy New Orleans issued notes due in three years in satisfaction of its affiliate prepetition accounts payable (approximately $74 million, including interest), including its indebtedness to the Entergy System money pool. In May 2010, Entergy New Orleans repaid, at maturity, the notes payable.

NOTE 6. PREFERRED EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)

The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and minority interest for Entergy Corporation subsidiaries as of December 31, 2010 and 2009 are presented below. All series of the Utility preferred stock are redeemable at the option of the related company.

	Shares/Units Authorized		Shares/Units Outstanding
	2010	2009	2010	2009	2010	2009
Entergy Corporation					(Dollars in Thousands)
Utility:
Preferred Stock or Preferred Membership Interests without sinking fund:
Entergy Arkansas, 4.32%-6.45% Series	3,413,500	3,413,500	3,413,500	3,413,500	$116,350	$116,350
Entergy Gulf States Louisiana, Series A 8.25 %	100,000	100,000	100,000	100,000	10,000	10,000
Entergy Louisiana, 6.95% Series (a)	1,000,000	1,000,000	840,000	840,000	84,000	84,000
Entergy Mississippi, 4.36%-6.25% Series	1,403,807	1,403,807	1,403,807	1,403,807	50,381	50,381
Entergy New Orleans, 4.36%-5.56% Series	197,798	197,798	197,798	197,798	19,780	19,780
Total Utility Preferred Stock or Preferred Membership Interests without sinking fund	6,115,105	6,115,105	5,955,105	5,955,105	280,511	280,511

Entergy Wholesale Commodities:
Preferred Stock without sinking fund:
Entergy Asset Management, 8.95% rate (b)	1,000,000	1,000,000	305,240	305,240	29,375	29,375
Other	-	-	-	-	852	1,457
Total Subsidiaries’ Preferred Stock without sinking fund	7,115,105	7,115,105	6,260,345	6,260,345	$310,738	$311,343

(a)

In 2007, Entergy Louisiana Holdings, an Entergy subsidiary, purchased 160,000 of these shares from the holders.

(b)

Upon the sale of Class B preferred shares in December 2009, Entergy Asset Management had issued and outstanding Class A and Class B preferred shares. The preferred stockholders’ agreement provides that during the 180 day period prior to each December 31 either Entergy Asset Management or the majority Class A or Class B preferred shareholders, each acting separately as a class, may request that the preferred dividend rate for the respective class be reset. If Entergy Asset Management and the respective preferred shareholders are unable to agree on a dividend reset rate, the preferred shareholder can request that its shares be sold to a third party (“Sale Election”). If Entergy Asset Management is unable to enter into an agreement in principle to sell the preferred shares within 75 days, the Class A preferred shareholders have the right to take control of the Entergy Asset Management board of directors for the purpose of liquidating the assets of Entergy Asset Management in order to repay the Class A preferred shares and any accrued dividends. Upon the sale of Class A shares resulting from a Sale Election or a liquidation transaction by the Class A preferred shareholders, Class B shareholders have the option to exchange their shares for shares of Class A preferred stock.

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Notes to Financial Statements

All outstanding preferred stock and membership interests are cumulative.

At December 31, 2010 and 2009, Entergy Gulf States Louisiana had outstanding 100,000 units of no par value 8.25% Series Preferred Membership Interests that were initially issued by Entergy Gulf States, Inc. as preference stock. The preference shares were converted into the preferred units as part of the jurisdictional separation. The distributions are cumulative and payable quarterly beginning March 15, 2008. The preferred membership interests are redeemable on or after December 15, 2015, at Entergy Gulf States Louisiana’s option, at the fixed redemption price of $100 per unit.

The number of shares and units authorized and outstanding and dollar value of preferred stock and membership interests for Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 2010 and 2009 are presented below. All series of the Utility operating companies’ preferred stock and membership interests are redeemable at the respective company’s option at the call prices presented. Dividends and distributions paid on all of Entergy’s preferred stock and membership interests series are eligible for the dividends received deduction. The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%.

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price per Share as of December 31,
	2010	2009	2010	2009	2010
Entergy Arkansas Preferred Stock
Without sinking fund:
Cumulative, $100 par value:
4.32% Series	70,000	70,000	$7,000	$7,000	$103.65
4.72% Series	93,500	93,500	9,350	9,350	$107.00
4.56% Series	75,000	75,000	7,500	7,500	$102.83
4.56% 1965 Series	75,000	75,000	7,500	7,500	$102.50
6.08% Series	100,000	100,000	10,000	10,000	$102.83
Cumulative, $25 par value:
6.45% Series (a)	3,000,000	3,000,000	75,000	75,000	$-
Total without sinking fund	3,413,500	3,413,500	$116,350	$116,350

	Shares/Units Authorized and Outstanding		Dollars (In Thousands)		Call Price per Share/Unit as of December 31,
	2010	2009	2010	2009	2010
Entergy Gulf States Louisiana Preferred Membership Interests
Without sinking fund:
Cumulative, $100 liquidation value:
8.25% Series (b)	100,000	100,000	$10,000	$10,000	$-
Total without sinking fund	100,000	100,000	$10,000	$10,000

	Units Authorized and Outstanding		Dollars (In Thousands)		Call Price per Unit as of December 31,
	2010	2009	2010	2009	2010
Entergy Louisiana Preferred Membership Interests
Without sinking fund:
Cumulative, $100 liquidation value:
6.95% Series (c)	1,000,000	1,000,000	$100,000	$100,000	$-
Total without sinking fund	1,000,000	1,000,000	$100,000	$100,000

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Notes to Financial Statements

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price per Share as of December 31,
	2010	2009	2010	2009	2010
Entergy Mississippi Preferred Stock
Without sinking fund:
Cumulative, $100 par value:
4.36% Series	59,920	59,920	$5,992	$5,992	$103.88
4.56% Series	43,887	43,887	4,389	4,389	$107.00
4.92% Series	100,000	100,000	10,000	10,000	$102.88
Cumulative, $25 par value
6.25% Series (d)	1,200,000	1,200,000	30,000	30,000	$-
Total without sinking fund	1,403,807	1,403,807	$50,381	$50,381

	Shares Authorized and Outstanding		Dollars (In Thousands)		Call Price per Share as of December 31,
	2010	2009	2010	2009	2010
Entergy New Orleans Preferred Stock
Without sinking fund:
Cumulative, $100 par value:
4.36% Series	60,000	60,000	$6,000	$6,000	$104.58
4.75% Series	77,798	77,798	7,780	7,780	$105.00
5.56% Series	60,000	60,000	6,000	6,000	$102.59
Total without sinking fund	197,798	197,798	$19,780	$19,780

(a)	Series is non-callable until April 2011; thereafter callable at par.
(b)	Series is non-callable until January 2016; thereafter callable at par.
(c)	Series is callable at par.
(d)	Series is callable at par.

NOTE 7. COMMON EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Common Stock

Common stock and treasury stock shares activity for Entergy for 2010, 2009, and 2008 is as follows:

	2010		2009		2008
	Common Shares Issued	Treasury Shares	Common Shares Issued	Treasury Shares	Common Shares Issued	Treasury Shares

Beginning Balance, January 1	254,752,788	65,634,580	248,174,087	58,815,518	248,174,087	55,053,847
Equity Unit Transaction	-	-	6,578,701	-	-	-
Repurchases	-	11,490,551	-	7,680,000	-	4,792,299
Issuances:
Employee Stock-Based Compensation Plans	-	(1,113,411)	-	(856,390)	-	(1,025,408)
Directors’ Plan	-	(4,800)	-	(4,548)	-	(5,220)
Ending Balance, December 31	254,752,788	76,006,920	254,752,788	65,634,580	248,174,087	58,815,518

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Notes to Financial Statements

In December 2005, Entergy Corporation sold 10 million equity units with a stated amount of $50 each. An equity unit consisted of (1) a note, initially due February 2011 and initially bearing interest at an annual rate of 5.75%, and (2) a purchase contract that obligated the holder of the equity unit to purchase for $50 between 0.5705 and 0.7074 shares of Entergy Corporation common stock on or before February 17, 2009. Entergy paid the holders quarterly contract adjustment payments of 1.875% per year on the stated amount of $50 per equity unit. Under the terms of the purchase contracts, Entergy attempted to remarket the notes in February 2009 but was unsuccessful, the note holders put the notes to Entergy, Entergy retired the notes, and Entergy issued shares of common stock to settle the purchase contracts.

Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), two Equity Ownership Plans of Entergy Corporation and Subsidiaries, the Equity Awards Plan of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors’ Plan awards to non-employee directors a portion of their compensation in the form of a fixed number of shares of Entergy Corporation common stock.

In January 2007, the Board approved a repurchase program that authorized Entergy to repurchase up to $1.5 billion of its common stock. In January 2008, the Board authorized an incremental $500 million share repurchase program to enable Entergy to consider opportunistic purchases in response to equity market conditions. Entergy completed both the $1.5 billion and $500 million programs in the third quarter 2009. In October 2009, the Board granted authority for an additional $750 million share repurchase program which was completed in the fourth quarter 2010. In October 2010, the Board granted authority for an additional $500 million share repurchase program.

Retained Earnings and Dividend Restrictions

Provisions within the articles of incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred equity. As of December 31, 2010, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had retained earnings unavailable for distribution to Entergy Corporation of $458 million and $241 million, respectively, and Entergy Louisiana had member’s equity unavailable for distribution to Entergy Corporation of $465 million. Entergy Corporation received dividend payments from subsidiaries totaling $580 million in 2010, $417 million in 2009, and $313 million in 2008.

Comprehensive Income

Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana. Accumulated other comprehensive income (loss) in the balance sheets included the following components:

	Entergy		Entergy Gulf States Louisiana		Entergy Louisiana
	December 31, 2010	December 31, 2009	December 31, 2010	December 31, 2009	December 31, 2010	December 31, 2009
	(In Thousands)

Cash flow hedges net unrealized gain	$106,258	$117,943	$-	$-	$-	$-
Pension and other postretirement liabilities	(276,466)	(267,939)	(40,304)	(42,171)	(24,962)	(25,539)
Net unrealized investment gains	129,685	72,162	-	-	-	-
Foreign currency translation	2,311	2,649	-	-	-	-
Total	($38,212)	($75,185)	($40,304)	($42,171)	($24,962)	($25,539)

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Other comprehensive income and total comprehensive income for years ended December 31, 2010, 2009, and 2008 are presented in Entergy’s, Entergy Gulf States Louisiana’s, and Entergy Louisiana’s Statements of Changes in Equity and Comprehensive Income.

NOTE 8. COMMITMENTS AND CONTINGENCIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Entergy and the Registrant Subsidiaries are involved in a number of legal, regulatory, and tax proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on Entergy’s results of operations, cash flows, or financial condition. Entergy discusses regulatory proceedings in Note 2 to the financial statements and discusses tax proceedings in Note 3 to the financial statements.

Vidalia Purchased Power Agreement

Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $216.5 million in 2010, $204.9 million in 2009, and $166.5 million in 2008. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $170.2 million in 2011, and a total of $2.64 billion for the years 2012 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause. In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to ten years, beginning in October 2002. In addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by $11.8 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election was not sustained. During the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election. The provisions of the settlement also provide that the LPSC shall not recognize or use Entergy Louisiana’s use of the cash benefits from the tax treatment in setting any of Entergy Louisiana’s rates. Therefore, to the extent Entergy Louisiana’s use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes.

Nuclear Insurance

Third Party Liability Insurance

1.	The primary level is private insurance underwritten by American Nuclear Insurers and provides public liability insurance coverage of $375 million. If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.

Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of $117.5 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.3 billion). This consists of a $111.9 million maximum retrospective premium plus a five percent surcharge, which equates to $117.5 million, that may be payable, if needed, at a rate that is currently set at $17.5 million per year per incident per nuclear power reactor. There is no limitation for terrorist acts as there had been in the past.

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Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $12.2 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

Entergy Arkansas has two licensed reactors and Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (SMEPA) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act). The Entergy Wholesale Commodities segment includes the ownership and operation of six nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.

Property Insurance

Entergy’s nuclear owner/licensee subsidiaries are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage, including decontamination and premature decommissioning expense, to the members’ nuclear generating plants. Effective April 1, 2010, Entergy was insured against such losses per the following structures:

Utility Plants (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3)

·	Primary Layer (per plant) - $500 million per occurrence

·	Excess Layer (per plant) - $750 million per occurrence

·	Blanket Layer (shared among the Utility plants) - $350 million per occurrence

·	Total limit - $1.6 billion per occurrence

·	Deductibles:

·	$2.5 million per occurrence - Turbine/generator damage

·	$2.5 million per occurrence - Other than turbine/generator damage

·	$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

Note: ANO 1 and 2 share in the primary and excess layers with common policies because the policies are issued on a per site basis.

Entergy Wholesale Commodities Plants (Indian Point, FitzPatrick, Pilgrim, Vermont Yankee, Palisades, and Big Rock Point)

·	Primary Layer (per plant) - $500 million per occurrence

·	Excess Layer - $615 million per occurrence

·	Total limit - $1.115 billion per occurrence

·	Deductibles:

·	$2.5 million per occurrence - Turbine/generator damage

·	$2.5 million per occurrence - Other than turbine/generator damage

·	$10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption

Note: The Indian Point Units share in the primary and excess layers with common policies because the policies are issued on a per site basis. Big Rock Point has its own primary policy with no excess coverage.

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In addition, Waterford 3, Grand Gulf, and the Entergy Wholesale Commodities plants are also covered under NEIL’s Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible and a waiting period. The following summarizes this coverage effective April 1, 2010:

Waterford 3

·	$2.95 million weekly indemnity

·	$413 million maximum indemnity

·	Deductible: 26 week waiting period

Grand Gulf

·	$400,000 weekly indemnity (total for four policies)

·	$56 million maximum indemnity (total for four policies)

·	Deductible: 26 week waiting period

Indian Point 2, Indian Point 3, and Palisades

·	$4.5 million weekly indemnity

·	$490 million maximum indemnity

·	Deductible: 12 week waiting period

FitzPatrick and Pilgrim

·	$4.0 million weekly indemnity

·	$490 million maximum indemnity

·	Deductible: 12 week waiting period

Vermont Yankee

·	$3.5 million weekly indemnity

·	$435 million maximum indemnity

·	Deductible: 12 week waiting period

Under the property damage and accidental outage insurance programs, all NEIL insured plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. Effective April 1, 2010, the maximum amounts of such possible assessments per occurrence were as follows:

		Assessments
		(In Millions)
Utility:
Entergy Arkansas		$21.3
Entergy Gulf States Louisiana		$16.3
Entergy Louisiana		$19.3
Entergy Mississippi		$0.07
Entergy New Orleans		$0.07
Entergy Texas		N/A
System Energy		$15.3

Entergy Wholesale Commodities		$-

Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.

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Notes to Financial Statements

Entergy maintains property insurance for its nuclear units in excess of the NRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

In the event that one or more acts of terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event.

Conventional Property Insurance

Entergy’s conventional property insurance program provides coverage of up to $400 million on an Entergy system-wide basis for all operational perils (direct physical loss or damage due to machinery breakdown, electrical failure, fire, lightning, hail, or explosion) on an “each and every loss” basis; up to $400 million in coverage for certain natural perils (direct physical loss or damage due to earthquake, tsunami, flood, ice storm, and tornado) on an annual aggregate basis; and up to $125 million for certain other natural perils (direct physical loss or damage due to a named windstorm or storm surge) on an annual aggregate basis. The conventional property insurance program provides up to $50 million in coverage for the Entergy New Orleans gas distribution system on an annual aggregate basis. The coverage is subject to a $20 million self-insured retention per occurrence for operational perils and a $35 million self-insured retention per occurrence for natural perils and for the Entergy New Orleans gas distribution system.

Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties. Excluded property generally includes above-ground transmission and distribution lines, poles, and towers. The primary layer consists of a $65 million layer in excess of the self-insured retention and the excess layer consists of a $335 million layer in excess of the $65 million primary layer. Both layers are placed on a quota share basis through several insurers. This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries, including the owners of the nuclear power plants in the Entergy Wholesale Commodities segment.

In addition to the conventional property insurance program, Entergy has purchased additional coverage ($20 million per occurrence) for some of its non-regulated, non-generation assets. This policy serves to buy-down the $20 million deductible and is placed on a scheduled location basis. The applicable deductibles are $100,000 to $250,000, except for properties that are damaged by flooding and properties whose values are greater than $20 million; these properties have a $500,000 deductible.

Gas System Rebuild Insurance Proceeds (Entergy New Orleans)

Entergy New Orleans received insurance proceeds for future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New Orleans’s rate and storm-cost recovery filings requires Entergy New Orleans to record those proceeds in a designated sub-account of other deferred credits until the proceeds are spent on the rebuild project. This other deferred credit is shown as “Gas system rebuild insurance proceeds” on Entergy New Orleans’s balance sheet.

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Employment and Labor-related Proceedings

The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees and third parties not selected for open positions. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board; claims of retaliation; and claims for or regarding benefits under various Entergy Corporation sponsored plans. Entergy and the Registrant Subsidiaries are responding to these suits and proceedings and deny liability to the claimants. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of Entergy or the Utility operating companies.

Asbestos Litigation (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Numerous lawsuits have been filed in federal and state courts primarily in Texas and Louisiana, primarily by contractor employees who worked in the 1940-1980s timeframe, against Entergy Gulf States Louisiana and Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos. Many other defendants are named in these lawsuits as well. Currently, there are approximately 500 lawsuits involving approximately 5,000 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.

Grand Gulf - Related Agreements

Capital Funds Agreement (System Energy)

System Energy has entered into agreements with Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy’s interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy’s operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation’s obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements.

Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

System Energy has agreed to sell all of its share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entergy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleans-17%) as ordered by the FERC. Charges under this agreement are paid in consideration for the purchasing companies’ respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered so long as the unit remains in commercial operation. The agreement will remain in effect until terminated by the parties and the termination is approved by the FERC, most likely upon Grand Gulf’s retirement from service. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 2010 under the agreement are approximately $17.1 million for Entergy Arkansas, $6.9 million for Entergy Louisiana, $14.2 million for Entergy Mississippi, and $8.3 million for Entergy New Orleans.

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Notes to Financial Statements

Availability Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17.1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy’s operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years. (See Reallocation Agreement terms below.) System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments.

Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC’s decision allocating a portion of Grand Gulf capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy Louisiana-26.23%, Entergy Mississippi-43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect Entergy Arkansas’s obligation to System Energy’s lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.

Reimbursement Agreement (System Energy)

In December 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million. The interests represent approximately 11.5% of Grand Gulf. During the term of the leases, System Energy is required to maintain letters of credit for the equity investors to secure certain amounts payable to the equity investors under the transactions.

Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and fixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%. In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings. As of December 31, 2010, System Energy was in compliance with these covenants.

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NOTE 9. ASSET RETIREMENT OBLIGATIONS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Accounting standards require the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. For Entergy, substantially all of its asset retirement obligations consist of its liability for decommissioning its nuclear power plants. In addition, an insignificant amount of removal costs associated with non-nuclear power plants is also included in the decommissioning line item on the balance sheets.

These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The accretion will continue through the completion of the asset retirement activity. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The application of accounting standards related to asset retirement obligations is earnings neutral to the rate-regulated business of the Registrant Subsidiaries.

In accordance with ratemaking treatment and as required by regulatory accounting standards, the depreciation provisions for the Registrant Subsidiaries include a component for removal costs that are not asset retirement obligations under accounting standards. In accordance with regulatory accounting principles, the Registrant Subsidiaries have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates:

	December 31,
	2010	2009
	(In Millions)

Entergy Arkansas	($24.0)	($7.3)
Entergy Gulf States Louisiana	($24.9)	($7.5)
Entergy Louisiana	($52.9)	($21.7)
Entergy Mississippi	$46.1	$44.5
Entergy New Orleans	$15.4	$15.2
Entergy Texas	$7.3	$7.2
System Energy	$12.2	$13.9

The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2010 by Entergy were as follows:

	Liabilities as of December 31, 2009	Accretion	Change in Cash Flow Estimate	Spending	Liabilities as of December 31, 2010
			(In Millions)
Utility:
Entergy Arkansas	$566.4	$35.8	$-	$-	$602.2
Entergy Gulf States Louisiana	$321.2	$18.7	$-	$-	$339.9
Entergy Louisiana	$298.2	$23.0	$-	$-	$321.2
Entergy Mississippi	$5.1	$0.3	$-	$-	$5.4
Entergy New Orleans	$3.2	$0.2	$-	$-	$3.4
Entergy Texas	$3.4	$0.2	$-	$-	$3.6
System Energy	$421.4	$31.4	$-	$-	$452.8

Entergy Wholesale Commodities	$1,320.6	$107.6	$-	($8.2)	$1,420.0

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The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2009 by Entergy were as follows:

	Liabilities as of December 31, 2008	Accretion	Change in Cash Flow Estimate	Spending	Liabilities as of December 31, 2009
			(In Millions)
Utility:
Entergy Arkansas	$540.7	$34.6	($8.9)	$-	$566.4
Entergy Gulf States Louisiana	$222.9	$19.6	$78.7	$-	$321.2
Entergy Louisiana	$276.8	$21.4	$-	$-	$298.2
Entergy Mississippi	$4.8	$0.3	$-	$-	$5.1
Entergy New Orleans	$3.0	$0.2	$-	$-	$3.2
Entergy Texas	$3.3	$0.1	$-	$-	$3.4
System Energy	$396.2	$29.4	($4.2)	$-	$421.4

Entergy Wholesale Commodities	$1,229.9	$99.3	$-	($8.6)	$1,320.6

Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. As described below, during 2009 Entergy updated decommissioning cost estimates for certain nuclear power plants. There were no updates to decommissioning cost estimates for 2010.

In the first quarter 2009, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and 2 as a result of a revised decommissioning cost study. The revised estimates resulted in an $8.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.

In the second quarter 2009, System Energy recorded a revision to its estimated decommissioning cost liabilities for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $4.2 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.

In the fourth quarter 2009, Entergy Gulf States Louisiana recorded a revision to its estimated decommissioning cost liabilities for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $78.7 million increase in its decommissioning liability, along with a corresponding increase in the related asset retirement obligation asset that will be depreciated over the remaining life of the units.

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require the Entergy subsidiaries to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. If the decommissioning liability is retained by NYPA, the Entergy subsidiaries will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy recorded an asset representing its estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning cost estimated in an independent decommissioning cost study. The asset is increased by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion is recorded as interest income.

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Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets of Entergy as of December 31, 2010 are as follows:

	Decommissioning Trust Fair Values	Regulatory Asset
	(In Millions)

Utility:
ANO 1 and ANO 2	$520.8	$161.4
River Bend	$393.6	$10.9
Waterford 3	$240.5	$104.2
Grand Gulf	$387.9	$98.3
Entergy Wholesale Commodities	$2,052.9	$-

The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets of Entergy as of December 31, 2009 are as follows:

	Decommissioning Trust Fair Values	Regulatory Asset
	(In Millions)

Utility:
ANO 1 and ANO 2	$440.2	$173.7
River Bend	$349.5	$11.0
Waterford 3	$209.1	$91.0
Grand Gulf	$327.0	$97.8
Entergy Wholesale Commodities	$1,885.4	$-

NOTE 10. LEASES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

General

As of December 31, 2010, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) with minimum lease payments as follows:

Year	Operating Leases	Capital Leases
	(In Thousands)

2011	$88,316	$6,494
2012	77,006	6,494
2013	69,160	6,494
2014	70,589	4,694
2015	53,828	4,694
Years thereafter	187,404	43,497
Minimum lease payments	546,303	72,367
Less: Amount representing interest	-	29,405
Present value of net minimum lease payments	$546,303	$42,962

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Total rental expenses for all leases (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $80.8 million in 2010, $71.6 million in 2009, and $66.4 million in 2008.

As of December 31, 2010, the Registrant Subsidiaries had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the sale and leaseback transactions) with minimum lease payments as follows:

Capital Leases

Year	Entergy Arkansas	Entergy Mississippi
	(In Thousands)

2011	$237	$3,370
2012	237	3,370
2013	237	3,370
2014	237	1,570
2015	237	1,570
Years thereafter	1,146	3,140
Minimum lease payments	2,331	16,390
Less: Amount representing interest	1,028	3,655
Present value of net minimum lease payments	$1,303	$12,735

Operating Leases

Year	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)

2011	$23,214	$11,231	$9,727	$6,168	$1,379	$5,005
2012	22,158	10,904	8,930	5,488	1,271	4,817
2013	20,824	10,334	8,025	5,018	1,227	4,612
2014	19,243	17,427	6,820	4,382	1,061	3,636
2015	20,565	8,094	4,797	3,390	961	1,538
Years thereafter	12,859	67,499	2,884	8,439	1,324	2,049
Minimum lease payments	$118,863	$125,489	$41,183	$32,885	$7,223	$21,657

Rental Expenses

Year	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Millions)

2010	$13.0	$12.5	$11.7	$5.5	$1.7	$7.4	$1.4
2009	$12.0	$11.6	$10.7	$5.3	$1.6	$9.9	$1.3
2008	$11.4	$11.6	$9.9	$5.6	$1.5	$7.8	$1.1

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In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $8.4 million in 2010, $7.2 million in 2009, and $10.2 million in 2008 for Entergy Arkansas and $2.3 million in 2010, $3.1 million in 2009, and $3.4 million in 2008 for Entergy Gulf States Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $3.4 million in 2010, $3.4 million in 2009, and $3.4 million in 2008.

Sale and Leaseback Transactions

Waterford 3 Lease Obligations

In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of $353.6 million. The interests represent approximately 9.3% of Waterford 3. The leases expire in 2017. Under certain circumstances, Entergy Louisiana may repurchase the leased interests prior to the end of the term of the leases. At the end of the lease terms, Entergy Louisiana has the option to repurchase the leased interests in Waterford 3 at fair market value or to renew the leases for either fair market value or, under certain conditions, a fixed rate.

Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the leases.

Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the interests in the unit and to pay an amount sufficient to withdraw from the lease transaction. Such events include lease events of default, events of loss, deemed loss events, or certain adverse “Financial Events.” “Financial Events” include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred membership interests) at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis. As of December 31, 2010, Entergy Louisiana was in compliance with these provisions.

As of December 31, 2010, Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows:

		Amount
		(In Thousands)

2011		$50,421
2012		39,067
2013		26,301
2014		31,036
2015		28,827
Years thereafter		77,994
Total		253,646
Less: Amount representing interest		29,844
Present value of net minimum lease payments		$223,802

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Notes to Financial Statements

Grand Gulf Lease Obligations

In December 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million. The interests represent approximately 11.5% of Grand Gulf. The leases expire in 2015. Under certain circumstances, System Entergy may repurchase the leased interests prior to the end of the term of the leases. At the end of the lease terms, System Energy has the option to repurchase the leased interests in Grand Gulf at fair market value or to renew the leases for either fair market value or, under certain conditions, a fixed rate.

In May 2004, System Energy caused the Grand Gulf lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate, and System Energy’s lease payments have been reduced to reflect the lower interest costs.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term. The amount was a net regulatory asset of $60.6 million and $93.1 million as of December 31, 2010 and 2009, respectively.

As of December 31, 2010, System Energy had future minimum lease payments (reflecting an implicit rate of 5.13%), which are recorded as long-term debt as follows:

		Amount
		(In Thousands)

2011		$49,437
2012		49,959
2013		50,546
2014		51,637
2015		52,253
Years thereafter		-
Total		253,832
Less: Amount representing interest		31,552
Present value of net minimum lease payments		$222,280

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Notes to Financial Statements

NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Qualified Pension Plans

Entergy has seven qualified pension plans covering substantially all employees: “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Retirement Plan II for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan II for Bargaining Employees,” “Entergy Corporation Retirement Plan III,” “Entergy Corporation Retirement Plan IV for Non-Bargaining Employees,” and “Entergy Corporation Retirement Plan IV for Bargaining Employees.” The Registrant Subsidiaries participate in two of these plans: “Entergy Corporation Retirement Plan for Non-Bargaining Employees” and “Entergy Corporation Retirement Plan for Bargaining Employees.” Except for the Entergy Corporation Retirement Plan III, the pension plans are noncontributory and provide pension benefits that are based on employees’ credited service and compensation during the final years before retirement. The Entergy Corporation Retirement Plan III includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earnings for a limited group of employees.

The assets of the seven qualified pension plans are held in a master trust established by Entergy. Each pension plan maintains an undivided beneficial interest in each of the investment accounts of the master trust that is maintained by a trustee. Use of the master trust permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative purposes. Although assets are commingled in the master trust, the trustee maintains supporting records for the purpose of allocating the equity in net earnings (loss) and the administrative expenses of the investment accounts to the various participating pension plans. The trustee determines the fair value of the fund and calculates a daily earnings factor, including realized and unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master trust on a pro rata basis.

Further, within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan’s actuary and is updated quarterly. Assets for each Registrant Subsidiary are increased for investment income and contributions, and decreased for benefit payments. A plan’s investment net income/(loss) (i.e. interest and dividends, realized gains and losses and expenses) is allocated to the Registrant Subsidiaries participating in that plan based on the value of assets for each Registrant Subsidiary at the beginning of the quarter adjusted for contributions and benefit payments made during the quarter.

Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Registrant Subsidiaries’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.

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Notes to Financial Statements

Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)

Entergy Corporation and its subsidiaries’ total 2010, 2009, and 2008 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

	2010	2009	2008
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period	$104,956	$89,646	$90,392
Interest cost on projected benefit obligation	231,206	218,172	206,586
Expected return on assets	(259,608)	(249,220)	(230,558)
Amortization of prior service cost	4,658	4,997	5,063
Recognized net loss	65,901	22,401	26,834
Net periodic pension costs	$147,113	$85,996	$98,317

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net (gain)/loss	$232,279	$76,799	$965,069
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(4,658)	(4,997)	(5,063)
Amortization of net loss	(65,901)	(22,401)	(26,834)
Total	161,720	49,401	933,172

Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)	$308,834	$135,397	$1,031,489

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Prior service cost	$3,350	$4,658	$4,997
Net loss	$92,977	$65,900	$22,401

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Notes to Financial Statements

The Registrant Subsidiaries’ total 2010, 2009, and 2008 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

2010	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period	$15,775	$8,462	$9,770	$4,651	$2,063	$4,267	$4,132
Interest cost on projected benefit obligation	49,277	24,377	28,541	15,230	6,040	15,869	9,009
Expected return on assets	(50,635)	(30,752)	(32,775)	(17,252)	(7,236)	(20,549)	(11,808)
Amortization of prior service cost	782	302	474	318	177	237	34
Recognized net loss	16,506	7,622	8,604	4,361	2,544	3,208	523
Net pension cost	$31,705	$10,011	$14,614	$7,308	$3,588	$3,032	$1,890

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss	$97,117	$4,748	$99,129	$21,801	$22,600	$17,316	$56,756
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(782)	(302)	(474)	(318)	(177)	(237)	(34)
Amortization of net loss	(16,506)	(7,622)	(8,604)	(4,361)	(2,544)	(3,208)	(523)
Total	$79,829	($3,176)	$90,051	$17,122	$19,879	$13,871	$56,199

Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)	$111,534	$6,835	$104,665	$24,430	$23,467	$16,903	$58,089

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Prior service cost	$459	$79	$280	$152	$35	$65	$16
Net loss	$25,681	$9,118	$17,990	$6,717	$4,666	$5,579	$5,284

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Notes to Financial Statements

2009	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period	$13,601	$6,993	$7,896	$3,981	$1,701	$3,668	$3,519
Interest cost on projected benefit obligation	47,043	21,116	27,760	14,706	5,878	15,741	8,555
Expected return on assets	(48,749)	(30,065)	(32,789)	(16,943)	(7,261)	(20,740)	(11,064)
Amortization of prior service cost	849	438	474	341	206	321	34
Recognized net loss	7,058	319	2,817	1,289	1,225	168	439
Net pension cost/(income)	$19,802	($1,199)	$6,158	$3,374	$1,749	($842)	$1,483

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss/(gain)	$32,528	$36,704	$7,113	$5,609	$724	($3,444)	$5,076
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(849)	(438)	(474)	(341)	(206)	(321)	(34)
Amortization of net loss	(7,058)	(319)	(2,817)	(1,289)	(1,225)	(168)	(439)
Total	$24,621	$35,947	$3,822	$3,979	($707)	($3,933)	$4,603

Total recognized as net periodic pension cost/(income), regulatory asset, and/or AOCI (before tax)	$44,423	$34,748	$9,980	$7,353	$1,042	($4,775)	$6,086

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Prior service cost	$782	$302	$474	$318	$177	$237	$34
Net loss	$16,506	$7,621	$8,603	$4,362	$2,544	$3,207	$523

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Notes to Financial Statements

2008	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period	$14,335	$7,363	$8,230	$4,251	$1,779	$3,874	$3,719
Interest cost on projected benefit obligation	46,464	20,189	27,135	14,507	5,660	15,528	7,749
Expected return on assets	(47,060)	(28,658)	(32,535)	(16,299)	(7,355)	(20,188)	(9,810)
Amortization of prior service cost	892	438	478	361	205	321	34
Recognized net loss	9,212	461	3,679	1,941	1,280	621	366
Net pension cost/(income)	$23,843	($207)	$6,987	$4,761	$1,569	$156	$2,058

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss	$178,674	$118,804	$131,649	$64,245	$30,687	$81,016	$37,700
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(892)	(438)	(478)	(361)	(205)	(321)	(34)
Amortization of net loss	(9,212)	(461)	(3,679)	(1,941)	(1,280)	(621)	(366)
Total	$168,570	$117,905	$127,492	$61,943	$29,202	$80,074	$37,300

Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)	$192,413	$117,698	$134,479	$66,704	$30,771	$80,230	$39,358

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Prior service cost	$849	$438	$474	$341	$206	$321	$34
Net loss	$7,063	$323	$2,823	$1,299	$1,216	$200	$433

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Notes to Financial Statements

Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet for Entergy Corporation and its Subsidiaries as of December 31, 2010 and 2009

	December 31,
	2010	2009
	(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at beginning of year	$3,837,744	$3,305,315
Service cost	104,956	89,646
Interest cost	231,206	218,172
Actuarial loss	293,189	385,221
Employee contributions	894	852
Benefits paid	(166,771)	(161,462)
Balance at end of year	$4,301,218	$3,837,744

Change in Plan Assets
Fair value of assets at beginning of year	$2,607,274	$2,078,252
Actual return on plan assets	320,517	557,642
Employer contributions	454,354	131,990
Employee contributions	894	852
Benefits paid	(166,771)	(161,462)
Fair value of assets at end of year	$3,216,268	$2,607,274

Funded status	($1,084,950)	($1,230,470)

Amount recognized in the balance sheet
Non-current liabilities	($1,084,950)	($1,230,470)

Amount recognized as a regulatory asset
Prior service cost	$12,979	$16,376
Net loss	1,350,616	1,183,824
	$1,363,595	$1,200,200
Amount recognized as AOCI (before tax)
Prior service cost	$2,855	$4,116
Net loss	297,093	297,507
	$299,948	$301,623

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Notes to Financial Statements

Qualified Pension Obligations, Plan Assets, Funded Status, and Amounts Recognized in the Balance Sheet for the Registrant Subsidiaries as of December 31, 2010 and 2009

2010	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Change in Projected Benefit
Obligation (PBO)
Balance at beginning of year	$824,261	$405,228	$480,503	$255,057	$101,325	$266,371	$149,387
Service cost	15,775	8,462	9,770	4,651	2,063	4,267	4,132
Interest cost	49,277	24,377	28,541	15,230	6,040	15,869	9,009
Actuarial loss	108,171	11,050	106,227	25,438	24,211	21,055	56,841
Employee contribution	-	-	-	-	-	-	2
Benefits paid	(46,889)	(17,247)	(28,311)	(14,197)	(5,162)	(15,011)	(6,273)
Balance at end of year	$950,595	$431,870	$596,730	$286,179	$128,477	$292,551	$213,098

Change in Plan Assets
Fair value of assets at beginning of year	$494,732	$310,445	$328,520	$171,912	$72,046	$209,936	$91,061
Actual return on plan assets	61,690	37,054	39,872	20,889	8,847	24,289	11,893
Employer contributions	136,958	30,955	66,135	33,518	12,957	18,288	31,324
Employee contribution	-	-	-	-	-	-	2
Benefits paid	(46,889)	(17,247)	(28,311)	(14,197)	(5,162)	(15,011)	(6,273)
Fair value of assets at end of year	$646,491	$361,207	$406,216	$212,122	$88,688	$237,502	$128,007

Funded status	($304,104)	($70,663)	($190,514)	($74,057)	($39,789)	($55,049)	($85,091)

Amounts recognized in the balance sheet (funded status)
Non-current liabilities	($304,104)	($70,663)	($190,514)	($74,057)	($39,789)	($55,049)	($85,091)

Amounts recognized as regulatory asset
Prior service cost	$682	$88	$571	$191	$45	$86	$35
Net loss	427,122	141,052	289,726	119,333	71,035	11,940	117,419
	$427,804	$141,140	$290,297	$119,524	$71,080	$112,026	$117,454

Amounts recognized as AOCI (before tax)
Prior service cost	$-	$19	$-	$-	$-	$-	$-
Net loss	-	30,963	-	-	-	-	-
	$-	$30,982	$-	$-	$-	$-	$-

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Notes to Financial Statements

2009	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Change in Projected Benefit
Obligation (PBO)
Balance at beginning of year	$717,104	$320,220	$423,322	$224,605	$89,315	$240,666	$128,540
Service cost	13,601	6,993	7,896	3,981	1,701	3,668	3,519
Interest cost	47,043	21,116	27,760	14,706	5,878	15,741	8,555
Actuarial loss	90,303	73,059	46,963	25,774	9,000	21,311	13,423
Employee contribution	-	-	-	-	-	-	2
Benefits paid	(43,790)	(16,160)	(25,438)	(14,009)	(4,569)	(15,015)	(4,652)
Balance at end of year	$824,261	$405,228	$480,503	$255,057	$101,325	$266,371	$149,387

Change in Plan Assets
Fair value of assets at beginning of year	$407,158	$253,966	$273,473	$142,916	$60,104	$175,551	$71,648
Actual return on plan assets	106,556	66,610	72,862	37,186	15,404	45,823	19,316
Employer contributions	24,808	6,029	7,623	5,819	1,107	3,577	4,747
Employee contribution	-	-	-	-	-	-	2
Benefits paid	(43,790)	(16,160)	(25,438)	(14,009)	(4,569)	(15,015)	(4,652)
Fair value of assets at end of year	$494,732	$310,445	$328,520	$171,912	$72,046	$209,936	$91,061

Funded status	($329,529)	($94,783)	($151,983)	($83,145)	($29,279)	($56,435)	($58,326)

Amounts recognized in the balance sheet (funded status)
Non-current liabilities	($329,529)	($94,783)	($151,983)	($83,145)	($29,279)	($56,435)	($58,326)

Amounts recognized as regulatory asset
Prior service cost	$1,464	$331	$1,045	$509	$222	$324	$69
Net loss	346,511	141,661	199,201	101,893	50,980	97,832	61,186
	$347,975	$141,992	$200,246	$102,402	$51,202	$98,156	$61,255

Amounts recognized as AOCI (before tax)
Prior service cost	$-	$78	$-	$-	$-	$-	$-
Net loss	-	33,229	-	-	-	-	-
	$-	$33,307	$-	$-	$-	$-	$-

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Notes to Financial Statements

Other Postretirement Trusts

2010	Level 1	Level 2	Level 3	Total
	(In Thousands)
Equity securities:
Common collective trust (a)	$-	$211,835	$-	$211,835
Fixed income securities:
Interest-bearing cash	4,014	-	-	4,014
U.S. Government securities	37,823	52,326	-	90,149
Corporate debt instruments	-	37,128	-	37,128
Other:
International securities	-	1,756	-	1,756
State and local obligations	-	56,960	-	56,960
Total investments	$41,837	$360,005	$-	$401,842

Other pending transactions				193
Plus: Other postretirement assets included in the investments of the qualified pension trust				2,395
Total fair value of other postretirement assets				$404,430

2009	Level 1	Level 2	Level 3	Total
	(In Thousands)
Equity securities:
Corporate common stocks	$50,698	$-	$-	$50,698
Common collective trust (b)	-	140,096	-	140,096
Fixed income securities:
Interest-bearing cash	6,115	-	-	6,115
U.S. Government securities	25,487	50,714	-	76,201
Other:
Corporate debt instruments	-	35,099	-	35,099
State and local obligations	-	53,443	-	53,443
Total investments	$82,300	$279,352	$-	$361,652

Interest receivable				1,567
Other pending transactions				(3,156)
Plus: Other postretirement assets included in the investments of the qualified pension trust				2,336
Total fair value of other postretirement assets				$362,399

(a)	In 2010, there were two common collective trusts holding investments in accordance with stated objectives. The investment strategy of the both trusts was to capture the growth potential of equity markets by replicating the performance of a specified index. Net asset value per share of the common collective trusts estimated fair value.
(b)	In 2009, there was one common collective trust holding investments in accordance with stated objectives. The investment strategy of this trust was to capture the growth potential of equity markets by replicating the performance of a specified index. Net asset value per share of the common collective trusts estimated fair value.

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Notes to Financial Statements

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $3.8 billion and $3.4 billion at December 31, 2010 and 2009, respectively.

The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries as of December 31, 2010 and 2009 was as follows:

	December 31,
	2010	2009
	(In Thousands)

Entergy Arkansas	$864,476	$753,029
Entergy Gulf States Louisiana	$388,292	$369,092
Entergy Louisiana	$537,329	$435,725
Entergy Mississippi	$261,248	$235,988
Entergy New Orleans	$115,223	$91,345
Entergy Texas	$268,350	$248,919
System Energy	$185,904	$132,072

Estimated Future Benefit Payments

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligation at December 31, 2010, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for Entergy Corporation and its subsidiaries will be as follows:

	Estimated Future Benefits Payments
	Qualified Pension	Non-Qualified Pension	Other Postretirement (before Medicare Subsidy)	Estimated Future Medicare Subsidy Receipts
	(In Thousands)
Year(s)
2011	$163,212	$9,637	$68,816	$5,991
2012	$172,221	$8,716	$73,119	$6,829
2013	$183,364	$16,334	$77,715	$7,736
2014	$196,083	$13,451	$82,540	$8,694
2015	$210,586	$13,549	$87,629	$9,691
2016 - 2020	$1,342,629	$77,109	$523,912	$65,454

Based upon the same assumptions, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for the Registrant Subsidiaries will be as follows:

Estimated Future Qualified Pension Benefits Payments	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)

Year(s)
2011	$45,301	$16,841	$27,893	$13,887	$5,173	$14,716	$6,286
2012	$46,159	$17,650	$28,328	$14,571	$5,405	$15,331	$6,550
2013	$47,438	$18,446	$29,303	$15,385	$5,714	$16,025	$7,072
2014	$49,095	$19,466	$30,379	$16,276	$5,990	$16,596	$7,612
2015	$51,205	$20,802	$31,572	$17,151	$6,408	$17,204	$8,198
2016 - 2020	$304,194	$130,699	$183,268	$99,288	$39,730	$98,798	$57,340

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Notes to Financial Statements

Estimated Future Non-Qualified Pension Benefits Payments	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)
Year(s)
2011	$207	$256	$18	$107	$25	$1,354
2012	$210	$252	$17	$103	$24	$1,040
2013	$202	$245	$16	$109	$23	$1,023
2014	$290	$255	$14	$100	$23	$1,798
2015	$272	$237	$13	$95	$22	$812
2016 - 2020	$1,239	$1,101	$49	$511	$114	$3,865

Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy)	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Year(s)
2011	$15,474	$7,833	$9,472	$4,561	$4,723	$6,729	$2,162
2012	$16,142	$8,306	$9,851	$4,838	$4,815	$7,035	$2,326
2013	$16,793	$8,817	$10,301	$5,181	$4,887	$7,284	$2,484
2014	$17,439	$9,336	$10,784	$5,524	$4,979	$7,533	$2,645
2015	$18,112	$9,897	$11,272	$5,909	$5,100	$7,842	$2,819
2016 - 2020	$101,558	$58,347	$64,154	$34,332	$26,728	$44,412	$17,200

Estimated Future Medicare Part D Subsidy	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)
Year(s)
2011	$1,460	$674	$858	$554	$526	$679	$110
2012	$1,639	$761	$965	$612	$563	$749	$138
2013	$1,833	$848	$1,070	$676	$599	$825	$172
2014	$2,036	$938	$1,178	$742	$624	$900	$211
2015	$2,241	$1,029	$1,286	$802	$645	$968	$252
2016 - 2020	$14,486	$6,722	$8,135	$5,022	$3,441	$5,675	$2,057

Contributions

Entergy currently expects to contribute approximately $368.8 million to its pension plans and approximately $78 million to other postretirement plans in 2011. The expected 2011 pension and other postretirement plan contributions of the Registrant Subsidiaries are shown below. The required pension contributions will not be known with more certainty until the January 1, 2011 valuations are completed by April 1, 2011.

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The Registrant Subsidiaries expect to contribute approximately the following to the pension and other postretirement plans in 2011:

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	(In Thousands)

Pension Contributions	$107,114	$24,626	$52,959	$26,388	$10,631	$15,866	$24,988
Other Postretirement Contributions	$26,313	$7,833	$9,472	$5,027	$5,205	$5,153	$3,489

Actuarial Assumptions

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2010, and 2009 were as follows:

	2010	2009

Weighted-average discount rate:
Qualified pension	5.60% - 5.70%	6.10% - 6.30%
Other postretirement	5.50%	6.10%
Non-qualified pension	4.90%	5.40%
Weighted-average rate of increase in future compensation levels	4.23%	4.23%

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2010, 2009, and 2008 were as follows:

	2010	2009	2008

Weighted-average discount rate:
Qualified pension	6.10% - 6.30%	6.75%	6.50%
Other postretirement	6.10%	6.70%	6.50%
Non-qualified pension	5.40%	6.75%	6.50%
Weighted-average rate of increase in future compensation levels	4.23%	4.23%	4.23%
Expected long-term rate of return on plan assets:
Pension assets	8.50%	8.50%	8.50%
Other postretirement non-taxable assets	7.75%	8.50%	8.50%
Other postretirement taxable assets	5.50%	6.00%	5.50%

Entergy’s other postretirement benefit transition obligations are being amortized over 20 years ending in 2012.

The assumed health care cost trend rate used in measuring the December 31, 2010 APBO of Entergy was 8.5% for pre-65 retirees and 8% for post-65 retirees for 2011, gradually decreasing each successive year until it reaches 4.75% in 2019 and beyond for pre-65 retirees and 4.75% in 2018 and beyond for post-65 retirees. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of Entergy was 7.5% for 2010, gradually decreasing each successive year until it reaches 4.75% in 2016 and beyond. A one percentage point change in the assumed health care cost trend rate for 2010 would have the following effects:

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	1 Percentage Point Increase		1 Percentage Point Decrease
2010	Impact on the APBO	Impact on the sum of service costs and interest cost	Impact on the APBO	Impact on the sum of service costs and interest cost
	Increase /(Decrease) (In Thousands)

Entergy Corporation and its subsidiaries	$136,203	$13,833	($121,015)	($11,914)

A one percentage point change in the assumed health care cost trend rate for 2010 would have the following effects for the Registrant Subsidiaries:

	1 Percentage Point Increase		1 Percentage Point Decrease
2010	Impact on the APBO	Impact on the sum of service costs and interest cost	Impact on the APBO	Impact on the sum of service costs and interest cost
	Increase/(Decrease) (In Thousands)

Entergy Arkansas	$23,736	$2,405	($21,274)	($2,088)
Entergy Gulf States Louisiana	$16,236	$1,671	($14,444)	($1,440)
Entergy Louisiana	$15,165	$1,647	($13,581)	($1,420)
Entergy Mississippi	$7,577	$682	($6,775)	($593)
Entergy New Orleans	$4,766	$528	($4,336)	($460)
Entergy Texas	$10,824	$1,035	($9,716)	($901)
System Energy	$5,666	$595	($4,981)	($509)

Medicare Prescription Drug, Improvement and Modernization Act of 2003

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 became law. The Act introduces a prescription drug benefit cost under Medicare (Part D), which started in 2006, as well as a federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

The actuarially estimated effect of future Medicare subsidies reduced the December 31, 2010 and 2009 Accumulated Postretirement Benefit Obligation by $267 million and $215 million, respectively, and reduced the 2010, 2009, and 2008 other postretirement benefit cost by $26.6 million, $24.0 million and $24.7 million, respectively. In 2010, Entergy received $5.4 million in Medicare subsidies for prescription drug claims.

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Notes to Financial Statements

The actuarially estimated effect of future Medicare subsidies and the actual subsidies received for the Registrant Subsidiaries was as follows:

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
	Increase/(Decrease) In Thousands
Impact on 12/31/2010 APBO	($55,459)	($27,330)	($31,259)	($17,998)	($11,073)	($19,830)	($10,431)
Impact on 12/31/2009 APBO	($45,809)	($22,227)	($25,443)	($14,824)	($9,798)	($16,652)	($7,965)

Impact on 2010 other postretirement benefit cost	($5,254)	($3,401)	($3,143)	($1,649)	($1,070)	($1,109)	($1,068)
Impact on 2009 other postretirement benefit cost	($4,941)	($3,257)	($2,780)	($1,562)	($1,043)	($958)	($923)

Medicare subsidies received in 2010	$1,235	$715	$814	$420	$438	$625	$140

Non-Qualified Pension Plans

Entergy also sponsors non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. Entergy recognized net periodic pension cost related to these plans of $27.2 million in 2010, $23.6 million in 2009, and $17.2 million in 2008. In 2010 and 2009, Entergy recognized $9.3 million and $6.7 million, respectively in settlement charges related to the payment of lump sum benefits out of the plan that is included in the non-qualified pension plan cost above. The projected benefit obligation was $148.3 million and $147.9 million as of December 31, 2010 and 2009, respectively. The accumulated benefit obligation was $131.6 million and $134.1 million as of December 31, 2010 and 2009, respectively.

Entergy’s non-qualified, non-current pension liability at December 31, 2010 and 2009 was $138.7 million and $124.1 million, respectively; and its current liability was $9.6 million and $23.8 million, respectively. The unamortized transition asset, prior service cost and net loss are recognized in regulatory assets ($53.5 million at December 31, 2010 and $51.6 million at December 31, 2009) and accumulated other comprehensive income before taxes ($24.3 million at December 31, 2010 and $23 million at December 31, 2009.)

The Registrant Subsidiaries (except System Energy) participate in Entergy’s non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. The net periodic pension cost for the non-qualified plans for 2010, 2009, and 2008, was as follows:

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)
2010	$501	$162	$102	$206	$26	$683
2009	$395	$1,245	$30	$174	$84	$743
2008	$533	$313	$28	$218	$48	$908

Included in the 2010 net periodic pension cost above are settlement charges of $86 thousand for Entergy Arkansas, $80 thousand for Entergy Louisiana, and $5 thousand for Entergy Texas related to the lump sum benefits paid out of the plan. Included in Entergy Gulf States Louisiana’s 2009 cost above is a $947 thousand settlement charge related to the payment of lump sum benefits out of the plan.

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Notes to Financial Statements

The projected benefit obligation for the non-qualified plans as of December 31, 2010 and 2009 was as follows:

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)
2010	$3,791	$2,717	$124	$1,561	$320	$11,136
2009	$3,443	$3,272	$198	$1,453	$608	$9,542

The accumulated benefit obligation for the non-qualified plans as of December 31, 2010 and 2009 was as follows:

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)
2010	$3,387	$2,691	$124	$1,335	$294	$11,030
2009	$3,180	$3,181	$189	$1,257	$478	$9,474

The following amounts were recorded on the balance sheet as of December 31, 2010 and 2009:

2010	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)

Current liabilities	($207)	($256)	($18)	($107)	($25)	($1,354)
Non-current liabilities	($3,584)	($2,461)	($106)	($1,454)	($295)	($9,782)
Total Funded Status	($3,791)	($2,717)	($124)	($1,561)	($320)	($11,136)

Regulatory Asset	$2,207	$320	($37)	$654	$82	$618
Accumulated other comprehensive income (before taxes)	$-	$70	$-	$-	$-	$-

2009	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)

Current liabilities	($341)	($285)	($23)	($107)	($16)	($935)
Non-current liabilities	($3,102)	($2,986)	($175)	($1,346)	($592)	($8,607)
Total Funded Status	($3,443)	($3,272)	($198)	($1,453)	($608)	($9,542)

Regulatory Asset	$1,844	$685	$118	$592	$389	($1,209)
Accumulated other comprehensive income (before taxes)	$-	$160	$-	$-	$-	$-

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Notes to Financial Statements

Defined Contribution Plans

Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and its subsidiaries. The employing Entergy subsidiary makes matching contributions for all non-bargaining and certain bargaining employees to the System Savings Plan in an amount equal to 70% of the participants’ basic contributions, up to 6% of their eligible earnings per pay period. The 70% match is allocated to investments as directed by the employee.

Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries II (established in 2001), the Savings Plan of Entergy Corporation and Subsidiaries IV (established in 2002), the Savings Plan of Entergy Corporation and Subsidiaries VI (established in April 2007), and the Savings Plan of Entergy Corporation and Subsidiaries VII (established in April 2007) to which matching contributions are also made. The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and its subsidiaries.

Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $41.8 million in 2010, $41.9 million in 2009, and $38.4 million in 2008. The majority of the contributions were to the System Savings Plan.

The Registrant Subsidiaries’ 2010, 2009, and 2008 contributions to defined contribution plans were as follows:

Year	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas
	(In Thousands)

2010	$3,177	$1,792	$2,289	$1,886	$683	$1,626
2009	$3,197	$1,828	$2,356	$1,906	$732	$1,712
2008	$3,144	$1,741	$2,172	$1,884	$697	$1,622

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ENTERGY’S BUSINESS

Entergy is an integrated energy company engaged primarily in electric power production and retail electric distribution operations. Entergy own and operate power plants with approximately 30,000 MW of aggregate electric generating capacity, and Entergy is the second-largest nuclear power generator in the United States. Entergy deliver electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy generated annual revenues of $11.5 billion in 2010 and had approximately 15,000 employees as of December 31, 2010.

Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.

The Utility business segment includes the generation, transmission, distribution, and sale of electric power in service territories in four states that include portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business.

The Entergy Wholesale Commodities business segment includes the ownership and operation of six nuclear power plants located in the northern United States and the sale of the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners. Entergy Wholesale Commodities also owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers while it focuses on improving operating and financial performance of these plants, consistent with Entergy’s market-based point-of-view.

In the fourth quarter 2010, Entergy finished integrating its former Non-Utility Nuclear business segment and its non-nuclear wholesale asset business into the new Entergy Wholesale Commodities business in an internal reorganization. The prior period financial information in this Form 10-K has been restated to reflect the change in reportable segments.

See Note 13 to the financial statements for financial information regarding Entergy’s business segments.

Strategy

Entergy aspires to achieve industry-leading total shareholder returns in an environmentally responsible fashion by leveraging the scale and expertise inherent in its core nuclear and utility operations. Entergy’s scope includes electricity generation, transmission and distribution as well as natural gas transportation and distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency, and risk management. Entergy also focuses on portfolio management to make periodic buy, build, hold, or sell decisions based upon its analytically-derived points of view, which are updated as market conditions evolve.

Utility

The Utility business segment includes six wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Gulf States Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

The six retail utility subsidiaries are each regulated primarily by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by FERC because all of its transactions are at wholesale. The Utility continues to operate as a rate-regulated business as efforts toward deregulation have been abandoned or have not been initiated in its service territories. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.

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The Utility is focused on providing highly reliable and cost-effective electricity and gas service while working in an environment that provides the highest level of safety for its employees. Since 1998, the Utility has significantly improved key customer service, reliability, and safety metrics and continues to actively pursue additional improvements.

Customers

As of December 31, 2010, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:

		Electric Customers		Gas Customers
	Area Served	(In Thousands)	(%)	(In Thousands)	(%)

Entergy Arkansas	Portions of Arkansas	693	25%
Entergy Gulf States Louisiana	Portions of Louisiana	381	14%	92	48%
Entergy Louisiana	Portions of Louisiana	667	24%
Entergy Mississippi	Portions of Mississippi	437	16%
Entergy New Orleans	City of New Orleans*	157	6%	99	52%
Entergy Texas	Portions of Texas	408	15%
Total customers		2,743	100%	191	100%

*	Excludes the Algiers area of the city, where Entergy Louisiana provides electric service.

Electric Energy Sales

The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 2, 2010, Entergy reached a 2010 peak demand of 21,799 MWh, compared to the 2009 peak of 21,009 MWh recorded on June 24, 2009. Selected electric energy sales data is shown in the table below:

Selected 2010 Electric Energy Sales Data

	Entergy Arkansas	Entergy Gulf States Louisiana	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy	Entergy (a)
	(In GWh)
Sales to retail customers	22,004	19,823	30,649	13,743	5,069	16,142	-	107,510
Sales for resale:
Affiliates	7,853	8,516	2,860	268	906	3,758	8,692	-
Others	850	1,705	101	402	13	1,300	-	4,372
Total	30,707	30,044	33,610	14,413	5,988	21,200	8,692	111,882

Average use per residential customer (kWh)	14,592	16,961	16,480	16,572	13,401	16,689	-	15,943

(a)	Includes the effect of intercompany eliminations.

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The following table illustrates the Utility operating companies’ 2010 combined electric sales volume as a percentage of total electric sales volume, and 2010 combined electric revenues as a percentage of total 2010 electric revenue, each by customer class.

Customer Class	% of Sales Volume	% of Revenue

Residential	33.5	38.6
Commercial	25.8	26.5
Industrial (a)	34.6	25.3
Governmental	2.2	2.4
Wholesale/Other	3.9	7.2

(a)	Major industrial customers are in the chemical, petroleum refining, and pulp and paper industries.

See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2006-2010.

Selected 2010 Natural Gas Sales Data

Entergy New Orleans and Entergy Gulf States Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States Louisiana sold 10,817,774 and 7,942,714 Mcf, respectively, of natural gas to retail customers in 2010. In 2010, 96% of Entergy Gulf States Louisiana’s operating revenue was derived from the electric utility business, and only 4% from the natural gas distribution business. For Entergy New Orleans, 82% of operating revenue was derived from the electric utility business and 18% from the natural gas distribution business in 2010. Following is data concerning Entergy New Orleans’s 2010 retail operating revenue sources.

Customer Class	Electric Operating Revenue	Natural Gas Revenue

Residential	41%	54%
Commercial	36%	23%
Industrial	8%	9%
Governmental/Municipal	15%	14%

Retail Rate Regulation

General (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.

Entergy Arkansas

Fuel and Purchased Power Cost Recovery

Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007, the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.

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Storm Cost Recovery

See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Arkansas’s storm restoration costs.

Entergy Gulf States Louisiana

Fuel Recovery

Entergy Gulf States Louisiana’s electric rates include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

To help stabilize electricity costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

Entergy Gulf States Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

To help stabilize retail gas costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy Gulf States Louisiana’s filings to recover storm-related costs.

Entergy Louisiana

Fuel Recovery

Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

In the Delaney vs. Entergy Louisiana proceeding, the LPSC ordered Entergy Louisiana, beginning with the May 2000 fuel adjustment clause filing, to re-price costs flowed through its fuel adjustment clause related to the Evangeline gas contract so that the price included for fuel adjustment clause recovery shall thereafter be at the rate of the Henry Hub first of the month cash market price (as reported by the publication Inside FERC) plus $0.24 per mmBtu for the month for which the fuel adjustment clause is calculated, irrespective of the actual cost for the Evangeline contract quantity reflected in that month’s fuel adjustment clause.

To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC in 2001 to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

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In September 2002, Entergy Louisiana settled a proceeding that concerned a contract entered into by Entergy Louisiana to purchase, through 2031, energy generated by a hydroelectric facility known as the Vidalia project. In the settlement, the LPSC approved Entergy Louisiana’s proposed treatment of the regulatory effect of the benefit from a tax accounting election related to that project. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012 and 2013-2031. During the first eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively repealed or the IRS denies the entire deduction related to the tax accounting method. In addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by $11.8 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election was not sustained. During the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election. Note 8 to the financial statements contains further discussion of the obligations related to the Vidalia project.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.

Entergy Mississippi

Fuel Recovery

Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased energy costs. The rider utilizes projected energy costs filed quarterly by Entergy Mississippi to develop an energy cost rate. The energy cost rate is redetermined each calendar quarter and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy cost as of the second quarter preceding the redetermination. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

In August 2009 the MPSC retained an independent audit firm to audit Entergy Mississippi's fuel adjustment clause submittals for the period October 2007 through September 2009. The independent audit firm submitted its report to the MPSC in December 2009. The report does not recommend that any costs be disallowed for recovery. The report did suggest that some costs, less than one percent of the fuel and purchased power costs recovered during the period, may have been more reasonably charged to customers through base rates rather than through fuel charges, but the report did not suggest that customers should not have paid for those costs. In November 2009 the MPSC also retained another firm to review processes and practices related to fuel and purchased energy. The results of that review were filed with the MPSC in March 2010. In that report, the independent consulting firm found that the practices and procedures in activities that directly affect the costs recovered through Entergy Mississippi's fuel adjustment clause appear reasonable. Both audit reports were certified by the MPSC to the Mississippi Legislature, as required by Mississippi law.

Power Management Rider

The MPSC approved the purchase of the Attala power plant in November 2005. In December 2005, the MPSC issued an order approving the investment cost recovery through its power management rider and limited the recovery to a period that begins with the closing date of the purchase and ends the earlier of the date costs are incorporated into base rates or December 31, 2006. As a consequence of the events surrounding Entergy Mississippi’s

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ongoing efforts to recover storm restoration costs associated with Hurricane Katrina, in October 2006, the MPSC approved a revision to Entergy Mississippi’s power management rider. The revision has the effect of allowing Entergy Mississippi to recover the annual ownership costs of the Attala plant until such time as a general rate case is filed.

To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-half of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

Storm Cost Recovery

Entergy Mississippi maintains a storm damage reserve pursuant to orders of the MPSC and consistent with the regulatory accounting requirements. Entergy Mississippi's storm damage reserve is funded through its storm damage rider schedule. In December 2010, Entergy Mississippi filed with the MPSC a notice of its intent to revise the storm damage rider schedule to increase the level of monthly accruals to the storm damage reserve from the current level of $750,000 per month to $1.75 million per month, and to increase the current level of the storm reserve cap during which funds will accrue from $15 million to $25 million. The cap is the level of the storm reserve balance at which monthly accruals would temporarily cease, and under Entergy Mississippi’s current filing, when the reserve balance falls below $15 million, monthly accruals would begin to be collected until the cap again is reached. The amounts of the monthly accruals and the cap have not been revised since 2001 and the current amounts do not reflect the costs of current storm restoration activities. Consideration of Entergy Mississippi’s notice is pending.

Entergy New Orleans

Fuel Recovery

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. In June 2006, the City Council authorized the recovery of all Grand Gulf costs through Entergy New Orleans’s fuel adjustment clause (a significant portion of Grand Gulf costs was previously recovered through base rates), and continued that authorization in approving the October 2006 formula rate plan filing settlement. Effective June 2009, the majority of Grand Gulf costs were realigned to base rates and are no longer flowed through the fuel adjustment clause.

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In October 2005, the City Council approved modification of the current gas cost collection mechanism effective November 2005 in order to address concerns regarding its fluctuations, particularly during the winter heating season. The modifications are intended to minimize fluctuations in gas rates during the winter months.

To help stabilize retail gas costs, Entergy New Orleans received approval from the City Council to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy New Orleans hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.

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Entergy Texas

Fuel Recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost reviews are discussed in Note 2 to the financial statements.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Texas’s storm restoration costs.

Franchises

Entergy Arkansas holds exclusive franchises to provide electric service in approximately 307 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.

Entergy Gulf States Louisiana holds non-exclusive franchises, permits, or certificates of convenience and necessity to provide electric service in approximately 56 incorporated municipalities and the unincorporated areas of approximately 18 parishes, and to provide gas service in the City of Baton Rouge and the unincorporated areas of two parishes. Most of Entergy Gulf States Louisiana’s franchises have a term of 60 years. Entergy Gulf States Louisiana’s current electric franchises expire during 2015-2046.

Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 116 incorporated Louisiana municipalities. Most of these franchises have 25-year terms. Entergy Louisiana also supplies electric service in approximately 45 Louisiana parishes in which it holds non-exclusive franchises. Entergy Louisiana’s electric franchises expire during 2011-2036.

Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.

Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana). These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.

Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas was typically granted 50-year franchises, but recently has been receiving 25-year franchises. Entergy Texas’s electric franchises expire during 2011-2045.

The business of System Energy is limited to wholesale power sales. It has no distribution franchises.

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Property and Other Generation Resources

Generating Stations

The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2010, is indicated below:

	Owned and Leased Capability MW(1)
Company	Total	Gas/Oil	Nuclear	Coal	Hydro

Entergy Arkansas	4,787	1,669	1,835	1,209	74
Entergy Gulf States Louisiana	3,325	1,988	974	363	-
Entergy Louisiana	5,667	4,499	1,168	-	-
Entergy Mississippi	3,229	2,809	-	420	-
Entergy New Orleans	748	748	-	-	-
Entergy Texas	2,543	2,274	-	269	-
System Energy	1,126	-	1,126	-	-
Total	21,425	13,987	5,103	2,261	74

(1)	“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

The Entergy System's load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, and the economy. Summer peak load in the Entergy System service territory has averaged 21,119 MW from 2002-2010. In the 2002 time period, the Entergy System's long-term capacity resources, allowing for an adequate reserve margin, were approximately 3,000 MW less than the total capacity required for peak period demands. In this time period the Entergy System met its capacity shortages almost entirely through short-term power purchases in the wholesale spot market. In the fall of 2002, the Entergy System began a program to add new resources to its existing generation portfolio and began a process of issuing requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The Entergy System has adopted a long-term resource strategy that calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Entergy refers to this strategy as the "Portfolio Transformation Strategy". Over the past nine years, Portfolio Transformation has resulted in the addition of about 4,000 MW of new long-term resources, including the 580 MW Acadia resource that is expected to close by the end of the first quarter 2011. These figures do not include transactions currently in negotiations as a result of the Summer 2009 RFP. When the Summer 2009 RFP transactions are included in the Entergy System portfolio of long-term resources and adjusting for unit deactivations of older generation, the Entergy System is approximately 600 MW short of its projected 2012 peak load plus reserve margin. The remaining need is expected to be met through a nuclear uprate at Grand Gulf and limited-term resource procurements. The Entergy System will continue to access the spot power market to economically purchase energy in order to minimize customer cost. In addition, Entergy considers in its planning processes the notices from Entergy Arkansas and Entergy Mississippi regarding their future withdrawal from the System Agreement. Furthermore, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies' transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service.

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RFP Procurements

The RFPs issued by the Entergy System since the fall of 2002 have sought resources needed to meet near-term summer reliability requirements as well as longer-term resources through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. Detailed evaluation processes have been developed to analyze submitted proposals, and, with the exception of the January

2008 RFP and the 2008 Western Region RFP, each RFP has been overseen by an independent monitor. The following table illustrates the results of the RFP process for resources acquired since the Fall 2002 RFP. The contracts below were primarily with non-affiliated suppliers, with the exception of contracts with EWO Marketing for the sale of 185 MW to 206 MW from the RS Cogen plant and contracts with Entergy Power for the sale of approximately 100 MW from the Independence plant. In 2009, Entergy Louisiana requested permission from the LPSC to cancel the Little Gypsy Unit 3 re-powering project selected from the 2006 Long-Term RFP.

RFP

Short-

term 3rd

party

Limited-term

affiliate

Limited-

term 3rd

party

Long-term

affiliate

Long-term

3rd party

Total

Fall 2002

185-206 MW (a)

231 MW

101-121 MW (b)

718 MW (d)

1,235-1,276 MW

January 2003 supplemental

222 MW

Spring 2003

381 MW

(c)

381 MW

Fall 2003

390 MW

Fall 2004

1,250 MW

2006 Long-Term

538 MW (e)

789 MW (f)

1,327 MW

Fall 2006

780 MW

January 2008 (g)

2008 Western Region

300 MW

Summer 2008 (h)

200 MW

January 2009 Western Region

150-300 MW

July 2009 Baseload

336 MW (i)

336 MW

Total

222 MW

521-542 MW

3,532 MW

639-659 MW

1,657-1,807 MW

6,571-6,762 MW

(a)	Includes a conditional option to increase the capacity up to the upper bound of the range.
(b)	The contracted capacity increased from 101 MW to 121 MW in 2010.
(c)	This table does not reflect (i) the River Bend 30% life-of-unit purchased power agreements totaling approximately 300 MW between Entergy Gulf States Louisiana and Entergy Louisiana (200 MW), and between Entergy Gulf States Louisiana and Entergy New Orleans (100 MW) related to Entergy Gulf States Louisiana's unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun Electric Power Cooperative, Inc. or (ii) the Entergy Arkansas wholesale base load capacity life-of-unit purchased power agreements executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which were not included in retail rates); or (iii) 12-month agreements originally executed in 2005 and which are renewed annually between Entergy Arkansas and Entergy Gulf States Louisiana and Entergy Texas, and between Entergy Arkansas and Entergy Mississippi, relating to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which were not included in retail rates) to those companies. These resources were identified outside of the formal RFP process but were submitted as formal proposals in response to the Spring 2003 RFP, which confirmed the economic merits of these resources.
(d)	Entergy Louisiana's June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which a total of 75% of the output is sold to Entergy Gulf States Louisiana and Entergy Texas.
(e)	In 2009, Entergy Louisiana requested permission from the LPSC to cancel the Little Gypsy Unit 3 re-powering project.
(f)	Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility, of which one-third of the output was sold to Entergy Gulf States Louisiana prior to the purchase of one-third of the facility by Entergy Gulf States Louisiana in November 2009.

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(g)	At the direction of the LPSC, but with full reservation of all legal rights, Entergy Services issued the January 2008 RFP for Supply-Side Resources seeking fixed price unit contingent products. Although the LPSC request was directed to Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Services issued the RFP on behalf of all of the Utility operating companies. No proposals were selected from this RFP.
(h)	In October 2008, in response to the U.S. financial crisis, Entergy Services on behalf of the Utility operating companies terminated all long-term procurement efforts, including the long-term portion of the Summer 2008 RFP.
(i)	Represents the self-supply alternative considered in the RFP, consisting of a cost-based purchase by Entergy Texas, Entergy Louisiana, and Entergy Mississippi of wholesale baseload capacity from Entergy Arkansas.

Entergy Louisiana and Entergy New Orleans currently purchase, pursuant to ten-year purchased power agreements that expire in 2013, 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. The transaction, which originated from the Fall 2002 RFP, included an option for Entergy Louisiana and Entergy New Orleans to acquire an ownership interest in the unit for a total price of $80 million, subject to various adjustments. In March 2008, Entergy Louisiana and Entergy New Orleans provided notice of their intent to exercise the option. Entergy Louisiana and Entergy New Orleans are evaluating the economics of proceeding with this option and have been in discussions with Entergy Power regarding the terms and conditions of the ownership acquisition.

In September 2009, on behalf of the Utility operating companies, Entergy Services issued the Summer 2009 RFP seeking proposals for long-term capacity and energy through products offered in the RFP. The RFP included a self-build option at Entergy Louisiana’s Ninemile site. Entergy Services concluded its review and evaluation of the proposals submitted in response to the RFP in July 2010 and awarded five proposals. The awarded proposals included four acquisition proposals totaling approximately 2,800 MW (including the Ninemile self-build option identified in the RFP) and one PPA proposal totaling approximately 500 MW. Subsequent to the RFP selections, one of the acquisition proposals that had been selected for award was withdrawn by the bidder. Entergy Services, on behalf of the Utility operating companies, is negotiating definitive agreements associated with the selected proposals.

In December 2010, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Services issued the 2010 RFP for Long-Term Renewable Energy Resources seeking up to 233 MW of renewable generation resources to meet the requirements of an LPSC general order issued in December 2010.

Other Procurements From Third Parties

The above table does not include resource acquisitions made outside of the RFP process, including Entergy Mississippi's January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant, and Entergy Gulf States Louisiana's March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility. In addition, in October 2009, Entergy Louisiana entered into an agreement to acquire Unit 2 of the Acadia Energy Center, a 580 MW generating unit located near Eunice, Louisiana, from Acadia Power Partners, LLC, an independent power producer. The Acadia purchase is expected to close by the end of the first quarter 2011. The above table also does not reflect various limited- and long-term contracts that have been entered into in recent years by the Utility operating companies as a result of bilateral negotiations.

Interconnections

The Entergy System's generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are centrally dispatched and operated. Entergy's Utility operating companies are interconnected with many neighboring utilities. In addition, the Utility operating companies are members of the SERC Reliability Corporation. The primary purpose of SERC is to ensure the reliability and adequacy of the electric bulk power supply in the southeast region of the United States. SERC is a member of the North American Electric Reliability Corporation.

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Gas Property

As of December 31, 2010, Entergy New Orleans distributed and transported natural gas for distribution within Algiers and New Orleans, Louisiana, through a total of 34 miles of gas transmission pipeline, 1,678 miles of gas distribution pipeline, and 824 miles of gas service pipeline from the distribution mains to the customers. As of December 31, 2010, the gas properties of Entergy Gulf States Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States Louisiana's financial position.

Titles

The Entergy System's generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.

Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Texas, and is not subject to its mortgage lien. Lewis Creek is leased to and operated by Entergy Texas.

Fuel Supply

The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2008-2010 were:

	Natural Gas		Nuclear		Coal		Purchased Power
Year	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh

2010	22	5.39	36	.78	13	2.00	29	5.28
2009	19	5.64	34	.66	12	2.04	35	5.29
2008	19	10.28	30	.60	12	2.06	39	7.92

Actual 2010 and projected 2011 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, are:

	Natural Gas		Nuclear		Coal		Purchased Power
	2010	2011	2010	2011	2010	2011	2010	2011

Entergy Arkansas (a)	3%	11%	46%	46%	25%	25%	26%	17%
Entergy Gulf States Louisiana	25%	31%	29%	15%	9%	9%	37%	45%
Entergy Louisiana	27%	28%	37%	38%	2%	3%	34%	31%
Entergy Mississippi	35%	41%	3%	3%	20%	27%	42%	29%
Entergy New Orleans	30%	47%	24%	27%	9%	13%	37%	13%
Entergy Texas	35%	22%	14%	17%	10%	13%	41%	48%
System Energy (b)	-	-	100%	100%	-	-	-	-
Utility (a)	22%	23%	33%	34%	12%	13%	33%	30%

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(a)

Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2010 and is expected to provide approximately 1% of its generation in 2011.

(b)

Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

Some of the Utility’s gas-fired plants are capable of also using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2011, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.

Natural Gas

The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Long-term firm contracts for power plants comprise less than 25% of the Utility operating companies' total requirements. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.

Entergy Louisiana has a long-term natural gas supply contract, which expires in 2012, in which Entergy Louisiana agreed to purchase natural gas in annual amounts equal to approximately one-third of its projected annual fuel requirements for certain generating units. Annual demand charges associated with this contract are estimated to be $6.6 million.

Many factors, including wellhead deliverability, storage and pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power.

Coal

Entergy Arkansas has a long-term contract for low-sulfur Powder River Basin (PRB) coal which expires in 2011 and is expected to provide for approximately 30% of the total expected coal requirements for 2011. Entergy Arkansas has committed to four medium-term (one- to three-year) contracts that will supply approximately 62% of the total coal supply needs in 2011. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 8% of total coal requirements will be satisfied by spot market or over-the-counter purchases. Based on greater PRB coal deliveries and the high cost of foreign coal, no alternative coal consumption is expected at Entergy Arkansas during 2011. Entergy Arkansas has an existing long-term railroad transportation contract that will provide all of Entergy Arkansas’s coal transportation requirements for 2011 and will provide most of the transportation requirements for several years beyond 2011.

Entergy Gulf States Louisiana has executed three medium-term contracts for the supply of low-sulfur PRB coal for Nelson Unit 6 that will supply approximately 90% of Nelson Unit 6 coal needs in 2011. Additional PRB coal will be purchased through spot market or over-the-counter purchases provided that adequate transportation is available from BNSF Railway Company. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2011. Coal will be transported to Nelson via an existing rail transportation agreement with BNSF Railway Company during 2011.

For the year 2010, coal transportation delivery to all Utility operating company coal-fired units met coal demand at the plants. It is expected that improved delivery times experienced in 2009 and 2010 will continue through 2011. Both Entergy Arkansas and Entergy Gulf States Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.

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The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Gulf States Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of low-sulfur PRB coal requested for 2011. Entergy Gulf States Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.

Nuclear Fuel

The nuclear fuel cycle consists of the following:

·	mining and milling of uranium ore to produce a concentrate;

·	conversion of the concentrate to uranium hexafluoride gas;

·	enrichment of the uranium hexafluoride gas;

·	fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and

·	disposal of spent fuel.

System Fuels, a company owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, is responsible for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units, except for River Bend. System Fuels also maintains inventories of such materials during the various stages of processing. The Utility operating companies, except Entergy Gulf States Louisiana, purchase enriched uranium hexafluoride from System Fuels, but contract separately for the fabrication of their own nuclear fuel. The requirements for River Bend are met pursuant to contracts made by Entergy Gulf States Louisiana. All contracts for the disposal of spent nuclear fuel are between the Department of Energy (DOE) and each of the nuclear power plants.

Based upon currently planned fuel cycles, the nuclear units in both the Utility and Entergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2011, and with substantial additional amounts after that time. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the creditworthiness and performance reliability of uranium miners, as well as upon the structure of Entergy’s contracts for the purchase of nuclear fuel. There are a number of possible alternate suppliers that may be accessed to mitigate unexpected supply disruption events, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.

Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the United States.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These arrangements are subject to periodic renewal.

Natural Gas Purchased for Resale

Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans has a "no-notice" service gas purchase contract with Atmos Energy which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Atmos Energy gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments.

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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy New Orleans's suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.

Entergy Gulf States Louisiana purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. The gas is delivered through a combination of intrastate and interstate pipelines.

Federal Regulation of the Utility

State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. FERC regulates wholesale rates (including intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.

System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the Utility operating companies. The System Agreement provides, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) shall receive payments from those parties having generating reserves that are less than their allocated share of reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies are based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.

Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC. Entergy Arkansas indicated, however, that a properly structured replacement agreement could be a viable alternative. In November 2007, pursuant to the provisions of the System Agreement, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC. In light of the notices of Entergy Arkansas and Entergy Mississippi to terminate participation in the current System Agreement, in January 2008 the LPSC unanimously voted to direct the LPSC Staff to begin evaluating the potential for a new agreement. Likewise, the New Orleans City Council opened a docket to gather information on progress towards a successor agreement.

In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96 month notice period without payment of a fee or being required to otherwise compensate the remaining Utility operating companies as a result of withdrawal. The FERC stated it expected Entergy and all interested parties to move forward and develop details of all needed successor arrangements and encouraged Entergy to file its Section 205 filing for post 2013 arrangements as soon as possible. In February 2011 the FERC denied the LPSC’s and the City Council’s rehearing requests. The LPSC has appealed the FERC’s decision to the U.S. Court of Appeals for the District of Columbia.

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See “System Agreement” in Entergy Corporation and Subsidiaries Management’s Discussion and Analysis for discussion of the proceedings at the FERC involving the System Agreement and other related proceedings.

Transmission

See “Independent Coordinator of Transmission” in the “Rate, Cost-recovery, and Other Regulation” section of Entergy Corporation and Subsidiaries Management’s Discussion and Analysis.

System Energy and Related Agreements

System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001, the rate proceeding became final, with the FERC approving a prospective 10.94% return on equity. The FERC’s decision also affected other aspects of System Energy’s charges to the Utility operating companies that it supplies with power. In 1998, the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by FERC.

Unit Power Sales Agreement

The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered, so long as Grand Gulf remains in commercial operation. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.

In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval.

Availability Agreement

The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.

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Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate) and interest charges. The September 1989 write-off of System Energy’s investment in Grand Gulf 2, amounting to approximately $900 million, is being amortized for Availability Agreement purposes over 27 years.

The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.

System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under “Sale and Leaseback Transactions - Grand Gulf Lease Obligations.” In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.

Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.

The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to FERC for approval with respect to the terms of such sale. No such filing with FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to FERC for approval.

Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement. Therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.

The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.

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Capital Funds Agreement

System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.

Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under “Sale and Leaseback Transactions - Grand Gulf Lease Obligations.” Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy’s rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.

The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement.

Service Companies

Entergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.

Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas

Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Management believes that the jurisdictional separation will better align Entergy Gulf States, Inc.’s Louisiana and Texas operations to serve customers in those states and to operate consistent with state-specific regulatory requirements as the utility regulatory environments in those jurisdictions evolve. The jurisdictional separation provides for regulation of each separated company by a single retail regulator, which should reduce regulatory complexity.

Entergy Texas now owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Gulf States Louisiana now owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.

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Entergy Gulf States Louisiana remained primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed its pro rata share of this long-term debt, which was $1.079 billion, or approximately 46%, which has been entirely paid-off as of December 31, 2010. The pro rata share of the long-term debt assumed by Entergy Texas was determined by first determining the net assets for each company on a book value basis, and then calculating a debt assumption ratio that resulted in the common equity ratios for each company being approximately the same as the Entergy Gulf States, Inc. common equity ratio immediately prior to the jurisdictional separation.

Entergy Texas purchases from Entergy Gulf States Louisiana pursuant to a life-of-unit purchased power agreement (PPA) a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the PPA. Entergy Gulf States Louisiana purchases a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas purchases a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Gulf States Louisiana. The PPAs associated with the gas-fired generating plants will terminate when the unit(s) is/are no longer dispatched by the Entergy System. The dispatch and operation of the generating plants will not change as a result of the jurisdictional separation.

The jurisdictional separation occurred through completion of the following steps:

·	Through a Texas statutory merger-by-division, Entergy Gulf States, Inc. was renamed as Entergy Gulf States Louisiana, Inc., a Texas corporation, and the new Texas business corporation Entergy Texas, Inc. was formed.

·	Entergy Gulf States, Inc. allocated the assets described above to Entergy Texas, and all of the capital stock of Entergy Texas was issued directly to Entergy Gulf States, Inc.’s parent company, Entergy Corporation.

·	Entergy Corporation formed EGS Holdings, Inc., a Texas corporation, and contributed all of the common stock of Entergy Gulf States Louisiana, Inc. to EGS Holdings, Inc.

·	EGS Holdings, Inc. formed the Louisiana limited liability company Entergy Gulf States Louisiana, L.L.C. and then owned all of the issued and outstanding membership interests of Entergy Gulf States Louisiana, L.L.C.

·	Entergy Gulf States Louisiana, Inc. then merged into Entergy Gulf States Louisiana, L.L.C., with Entergy Gulf States Louisiana, L.L.C. being the surviving entity.

·	Entergy Corporation now owns EGS Holdings, Inc. and Entergy Texas in their entirety, and EGS Holdings, Inc. now owns Entergy Gulf States Louisiana’s common membership interests in their entirety.

Earnings Ratios of Registrant Subsidiaries

The Registrant Subsidiaries’ ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:

	Ratios of Earnings to Fixed Charges Years Ended December 31,
	2010	2009	2008	2007	2006

Entergy Arkansas	3.91	2.39	2.33	3.19	3.37
Entergy Gulf States Louisiana	3.58	2.99	2.44	2.84	3.01
Entergy Louisiana	3.41	3.52	3.14	3.44	3.23
Entergy Mississippi	3.30	3.25	2.92	3.22	2.54
Entergy New Orleans	4.41	3.66	3.71	2.74	1.52
Entergy Texas	2.10	1.92	2.04	2.07	2.12
System Energy	3.64	3.73	3.29	3.95	4.05

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	Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31,
	2010	2009	2008	2007	2006

Entergy Arkansas	3.50	2.09	1.95	2.88	3.06
Entergy Gulf States Louisiana	3.53	2.95	2.42	2.73	2.90
Entergy Louisiana	3.13	3.27	2.87	3.08	2.90
Entergy Mississippi	3.06	3.01	2.67	2.97	2.34
Entergy New Orleans	3.97	3.38	3.45	2.54	1.35

The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.

Entergy Wholesale Commodities

During 2010 Entergy integrated its former Non-Utility Nuclear and non-nuclear wholesale assets businesses into a new organization called Entergy Wholesale Commodities.

Entergy Wholesale Commodities includes the ownership and operation of six nuclear power plants, five of which are located in the Northeast United States, with the sixth located in Michigan, and is primarily focused on selling electric power produced by those plants to wholesale customers. Entergy Wholesale Commodities’ revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning services, to nuclear power plants owned by other utilities in the United States.

Entergy Wholesale Commodities also includes the ownership, or participation in joint ventures that own, non-nuclear power plants and the sale to wholesale customers of the electric power produced by these plants while it focuses on improving their operating and financial performance, consistent with Entergy’s market-based point-of-view.

Property

Nuclear Generating Stations

Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:

Power Plant

Market

Service

Year

Acquired

Location

Capacity-

Reactor Type

License

Expiration

Date

Pilgrim

IS0-NE

1972

July 1999

Plymouth, MA

688 MW - Boiling Water

2012

FitzPatrick

NYISO

1975

Nov. 2000

Oswego, NY

838 MW - Boiling Water

2034

Indian Point 3

NYISO

1976

Nov. 2000

Buchanan, NY

1,041 MW - Pressurized Water

2015

Indian Point 2

NYISO

1974

Sept. 2001

Buchanan, NY

1,028 MW - Pressurized Water

2013

Vermont Yankee

IS0-NE

1972

July 2002

Vernon, VT

605 MW - Boiling Water

2012

Palisades

MISO

1971

Apr. 2007

South Haven, MI

798 MW - Pressurized Water

2031

Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York, that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process.

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The operating licenses for Vermont Yankee, Pilgrim, Indian Point 2, and Indian Point 3 expire between 2012 and 2015. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. Various parties have expressed opposition to renewal of the licenses. Renewal of the Indian Point licenses is the subject of ongoing proceedings, which are discussed further below, before the Atomic Safety and Licensing Board (ASLB) of the NRC. Certain contentions have been admitted for litigation, and new and amended contentions filed by parties in January and February 2011 have not been acted upon by the ASLB. Hearings on the contentions admitted by the ASLB currently are expected to begin in early 2012. The ASLB completed its proceedings regarding Vermont Yankee, but the New England Coalition filed a new contention that the ASLB denied in October 2010. The New England Coalition requested NRC review of the denial in November 2010. Finally, with respect to the Pilgrim license renewal, the NRC has issued decisions resolving all but one of the issues that were previously appealed by Pilgrim Watch. The NRC remanded one issue, to the ASLB, which ordered that testimony be filed in January 2011 and scheduled a hearing for March 2011. Meanwhile, Pilgrim Watch filed two new contentions, one of which it subsequently amended, in December 2010 and January 2011. The ASLB has not decided whether to admit or deny the new Pilgrim Watch contentions.

In addition to its federal NRC license, there is a two-step state law licensing process for obtaining a Certificate of Public Good (CPG) to operate Vermont Yankee and store spent nuclear fuel beyond March 21, 2012, when the current CPG expires. First, the Vermont legislature must vote affirmatively to permit the Vermont Public Service Board to consider Vermont Yankee’s application for a renewed CPG for the continued operation of Vermont Yankee and for storage of spent fuel. Second, the Vermont Public Service Board must vote to renew the CPG. The Entergy affiliates that own and operate Vermont Yankee filed an application with the Vermont Public Service Board in March 2008 for a certificate of public good to operate for 20 years beginning March 22, 2012 and to store spent nuclear fuel generated after that date. Ten days of hearings were held in May and June 2009. The Department of Public Service and other parties contended during the hearing that a favorable power purchase agreement for the sale of power from Vermont Yankee to Vermont utilities would be important to demonstrating that renewal of the certificate of public good promoted the public interest. Proceedings in that docket currently are in abeyance.

During its 2009 session, which concluded in May, several committees of the Vermont General Assembly held hearings on Vermont Yankee, but no bill or resolution was introduced for approval of continued operation and storage of spent nuclear fuel generated after March 21, 2012. In January 2010, the Governor of the State of Vermont issued a statement indicating he would not ask the Vermont General Assembly to consider the renewal of a certificate of public good during its 2010 session, based on the discovery of tritium leakage from Vermont Yankee, concerns about miscommunication by Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations related to underground piping at Vermont Yankee carrying radionuclides, and other issues including decommissioning. Nevertheless, on February 24, 2010, a bill to authorize the Vermont Public Service Board to approve the continued operation of Vermont Yankee was defeated in the Vermont Senate by a vote of 26 to 4. Neither house of the Vermont General Assembly has voted on a similar bill since that time.

In April 2007, Entergy submitted an application to the NRC to renew the operating licenses for Indian Point 2 and 3 for an additional 20 years. The NRC Staff currently is performing its technical and environmental reviews of the application. It issued a draft supplemental environmental impact statement in December 2008, a final supplemental environmental impact statement in December 2010, a safety evaluation with open items in January 2009, and a final safety evaluation report in August 2009. The New York Department of Environmental Conservation has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. Indian Point also must obtain a Coastal Zone Management Act consistency determination from the New York Department of State prior to getting its renewed license. For a discussion concerning the status of Entergy Wholesale Commodities’ efforts to obtain these certifications and determinations, see “Environmental Regulation, Clean Water Act” below.

In July 2008, the ASLB admitted 17 contentions raised by the State of New York, Riverkeeper, and Clearwater that were then combined into 13 issues. In June 2010, the ASLB admitted two additional contentions raised by the State of New York, which were combined into one issue. In total, there are 19 admitted contentions that have been consolidated into 14 discrete issues. The ASLB issued its initial case management and schedule order during the first

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quarter 2009, although the parties began the discovery process pursuant to an ASLB order issued in December 2008 and an agreement reached by the parties in January 2009 regarding disclosure issues. In January and February 2011, the State of New York, Riverkeeper, and Clearwater submitted new and amended contentions to the ASLB based on the NRC's updated Waste Confidence Rule and the NRC's Final Supplemental Environmental Impact Statement issued for Indian Point license renewal. The ASLB has not yet acted on the proposed new and amended contentions. Evidentiary hearings on the admitted contentions are currently expected to begin in early 2012.

The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Entergy intends to participate fully in the hearing process as permitted by the NRC’s hearing rules. As noted in Entergy’s responses to the various petitions to intervene, Entergy believes that many of the issues raised by the petitioners are unsupported and without merit. Furthermore, Entergy believes that it will carry its burden of proof with respect to any issues that were admitted for evidentiary hearings. Entergy will continue to work with the NRC Staff as it completes its technical and environmental reviews of the license renewal application.

Non-nuclear Generating Stations

Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:

Plant	Location	Ownership	Net Owned Capacity(1)	Type

Ritchie Unit 2, 544 MW	Helena, AR	100%	544 MW	Gas/Oil
Independence Unit 2, 842 MW (2)	Newark, AR	14%	121 MW(3)	Coal
Top of Iowa, 80 MW (4)	Worth County, IA	50%	40 MW	Wind
White Deer, 80 MW (4)	Amarillo, TX	50%	40 MW	Wind
RS Cogen, 425 MW (4)	Lake Charles, LA	50%	213 MW	Gas/Steam

(1)	“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(2)	Entergy Louisiana and Entergy New Orleans currently purchase 101 MW of capacity and energy from Independence Unit 2. The transaction included an option for Entergy Louisiana and Entergy New Orleans to acquire an ownership interest in the unit for a total price of $80 million, subject to various adjustments. On March 5, 2008, Entergy Louisiana and Entergy New Orleans provided notice of their intent to exercise the option. The parties are negotiating the terms and conditions of the ownership acquisition.
(3)	The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
(4)	Indirectly owned through interests in unconsolidated joint ventures.

In addition to these generating stations, Entergy Wholesale Commodities has a contract to take 60 MW of the power from a portion of the Nelson 6 coal plant owned by a third party.

In the fourth quarter 2010, Entergy sold its 61 percent share of the Harrison County 550 MW combined cycle gas-fired power plant.

Interconnections

The Pilgrim and Vermont Yankee plants fall under the authority of the Independent System Operator (ISO) New England and the FitzPatrick and Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the Midwest Independent System Operator (MidwestISO). The primary purpose of ISO New England, NYISO and MidwestISO is to direct the operations of the major generation and transmission facilities in their respective regions and in doing so also takes responsibility for ensuring grid reliability, administering and monitoring wholesale electricity markets and planning for their respective region’s energy needs.

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Energy and Capacity Sales

As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity to load-serving entities, which allows those companies to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward fixed price power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy to its counterparties, make capacity available to them, or both. See “Commodity Price Risk - Power Generation” in Entergy Corporation and Subsidiaries Management’s Discussion and Analysis for additional information regarding these contracts.

In addition to the contracts discussed in “Commodity Price Risk - Power Generation,” Entergy’s purchase of the Vermont Yankee plant included a value sharing agreement providing for payments to the seller in the event that the plant’s operating license term is renewed beyond its original expiration in 2012. Under the value sharing agreement, to the extent that the average annual price of the energy sales from the plant exceeds the specified strike price, initially $61/MWh and then adjusted annually based on three indices, Vermont Yankee will pay 50% of the amount exceeding the strike prices to the seller. These payments, if required, will be recorded as adjustments to the purchase price of the plants. The value sharing would begin in 2012 and extend into 2022.

As part of the purchase of the Palisades plant, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy will receive the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value.

Customers

Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations and other power generation companies. These customers include Consolidated Edison, NYPA, and Consumers Energy, companies from which Entergy purchased plants, and ISO New England and NYISO. As of December 31, 2010, the counterparties or their guarantors for 99.7% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2015 have public investment grade credit ratings and 0.3% is with load-serving entities without public credit ratings.

Competition

The ISO New England and NYISO markets are highly competitive. Entergy Wholesale Commodities has approximately 85 competitors in New England and 70 competitors in New York, including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in these markets. Based on the latest available information, Entergy Wholesale Commodities plants provided approximately 7% of the aggregate net generation capacity serving the New England power market

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and 16% of the aggregate net generation capacity serving the New York power market. The MidwestISO market includes approximately 280 participants. The MidwestISO does not have a formal, centralized forward capacity market, but load serving entities do transact capacity through bilateral contracts. Palisades’s current output is fully contracted to Consumers Energy through 2022 and, therefore, Entergy Wholesale Commodities does not expect to be materially affected by competition in the MidwestISO market in the near term.

Seasonality

Entergy Wholesale Commodities’ revenues and operating income are subject to mild fluctuations during the year due to seasonal factors and weather conditions. When outdoor and cooling water temperatures are lower, generally during colder months, Entergy Wholesale Commodities’ nuclear power plants operate more efficiently, and consequently, generate more electricity. Although some of its annual contracts provide for monthly pricing, Entergy Wholesale Commodities derives the majority of its revenues from fixed price forward power sales that are generally sold at a single price for a calendar year, which can offset the effects of seasonality and weather conditions on monthly power prices.

Fuel Supply

Nuclear Fuel

See “Fuel Supply, Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities’ nuclear power plants, while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plants.

Other Business Activities

Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM functions include origination of new energy and capacity transactions, generation scheduling, contract management (including billing and settlements), and market and credit risk mitigation.

Entergy Nuclear, Inc. pursues service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities for Entergy Wholesale Commodities with other nuclear plant owners through operating agreements or innovative arrangements such as structured leases.

Entergy Nuclear, Inc. also offers operating license renewal and life extension services to nuclear power plant owners. TLG Services, a subsidiary of Entergy Nuclear Inc., offers decommissioning, engineering, and related services to nuclear power plant owners. In April 2009, Entergy announced that it will team with energy firm ENERCON to offer nuclear development services ranging from plant relicensing to full-service, new plant deployment. ENERCON has experience in engineering, environmental, technical and management services.

In September 2003, Entergy agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The original contract was to expire in 2014 corresponding to the original operating license life of the plant. In 2006, an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station. The Cooper Nuclear Station received its license renewal from the NRC on November 29, 2010. Entergy continues to provide implementation services for the renewed license. In 2010, an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029. The contract extension allows for Entergy to initially receive $16 million per year with an opportunity to receive an additional $4 million if safety and regulatory goals are met.

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Entergy-Koch

Entergy-Koch is a joint venture owned 50% each by Entergy and Koch Industries, Inc, through subsidiaries. Entergy-Koch began operations on February 1, 2001. Entergy contributed most of the assets and trading contracts of its power marketing and trading business and $414 million cash to the venture and Koch contributed its approximately 8,000-mile Koch Gateway Pipeline (renamed Gulf South Pipeline), gas storage facilities, and Koch Energy Trading, which marketed and traded electricity, gas, weather derivatives, and other energy-related commodities and services. As specified in the partnership agreement, Entergy contributed an additional $72.7 million to the partnership in January 2004.

In the fourth quarter of 2004, Entergy-Koch sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales. Due to the November 2006 expiration of contingencies on the sale of Entergy-Koch’s trading business, and the corresponding release to Entergy-Koch of sales proceeds held in escrow, Entergy received additional cash distributions of approximately $163 million during the fourth quarter of 2006 and recorded a gain of approximately $55 million (net-of-tax). In December 2009, Entergy reorganized its investment in Entergy-Koch, received a $25.6 million cash distribution, and received a distribution of certain software owned by the joint venture. Entergy-Koch is no longer an operating entity.

Regulation of Entergy’s Business

Energy Policy Act of 2005

The Energy Policy Act of 2005 became law in August 2005. The legislation contains electricity provisions that, among other things:

Repealed PUHCA 1935, through enactment of PUHCA 2005, effective February 8, 2006; PUHCA 2005 and/or related amendments to Section 203(a) of the Federal Power Act (a) remove various limitations on Entergy Corporation as a registered holding company under PUHCA 1935; (b) require the maintenance and retention of books and records by certain holding company system companies for inspection by the FERC and state commissions, as appropriate; and (c) effectively leave to the jurisdiction of the FERC (or state or local regulatory bodies, as appropriate) (i) the issuance by an electric utility of securities; (ii) (A) the disposition of jurisdictional FERC electric facilities by an electric utility; (B) the acquisition by an electric utility of securities of an electric utility; (C) the acquisition by an electric utility of electric generating facilities (in each of the cases in (A), (B) and (C) only in transactions in excess of $10 million); (iv) electric public utility mergers; and (v) the acquisition by an electric public utility holding company of securities of an electric public utility company or its holding company in excess of $10 million or the merger of electric public utility holding company systems. PUHCA 2005 and the related FERC rule-making also provide a savings provision which permits continued reliance on certain PUHCA 1935 rules and orders after the repeal of PUHCA 1935.

Codifies the concept of participant funding or cost causation, a form of cost allocation for transmission interconnections and upgrades, and allows the FERC to apply participant funding in all regions of the country. Participant funding helps ensure that a utility’s native load customers only bear the costs that are necessary to provide reliable transmission service to them and do not bear costs for transmission projects that are not required for reliability and that are not anticipated to provide the customers net benefits.

Provides financing benefits, including loan guarantees and production tax credits, for new nuclear plant construction, and reauthorizes the Price-Anderson Act, the law that provides an umbrella of insurance protection for the payment of public liability claims in the event of a major nuclear power plant incident.

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·	Revises current tax law treatment of nuclear decommissioning trust funds by allowing regulated and non-regulated taxpayers to make deductible contributions to fund the entire amount of estimated future decommissioning costs.

·	Provides a more rapid tax depreciation schedule for transmission assets to encourage investment.

Creates mandatory electricity reliability guidelines with enforceable penalties to help ensure that the nation’s power transmission grid is kept in good repair and that disruptions in the electricity system are minimized. Entergy already voluntarily complies with National Electricity Reliability Council standards, which are similar to the guidelines mandated by the Energy Policy Act of 2005.

·	Establishes conditions for the elimination of the Public Utility Regulatory Policy Act’s (PURPA) mandatory purchase obligation from qualifying facilities.

·	Significantly increased the FERC’s authorization to impose criminal and civil penalties for violations of the provisions of the Federal Power Act.

Federal Power Act

The Federal Power Act provides the FERC the authority to regulate:

·	the transmission and wholesale sale of electric energy in interstate commerce;

·	sales or acquisition of certain assets;

·	securities issuances;

·	the licensing of certain hydroelectric projects;

·	certain other activities, including accounting policies and practices of electric and gas utilities; and

·	changes in control of FERC jurisdictional entities or rate schedules.

The Federal Power Act gives FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States Louisiana. FERC also regulates the rates charged for intrasystem sales pursuant to the System Agreement and the provision of transmission service to wholesale market participants.

Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.

State Regulation

Utility

Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:

·	oversee utility service;

·	set retail rates;

·	determine reasonable and adequate service;

·	control leasing;

·	control the acquisition or sale of any public utility plant or property constituting an operating unit or system;

·	set rates of depreciation;

·	issue certificates of convenience and necessity and certificates of environmental compatibility and public need; and

·	regulate the issuance and sale of certain securities.

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Entergy Gulf States Louisiana’s electric and gas business and Entergy Louisiana are subject to regulation by the LPSC as to:

·	utility service;

·	retail rates and charges;

·	certification of generating facilities;

·	power or capacity purchase contracts; and

·	depreciation and other matters.

Entergy Louisiana is also subject to the jurisdiction of the City Council with respect to such matters within Algiers in Orleans Parish, although the precise scope of that jurisdiction differs from that of the LPSC.

Entergy Mississippi is subject to regulation by the MPSC as to the following:

·	utility service;

·	service areas;

·	facilities; and

·	retail rates.

Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.

Entergy New Orleans is subject to regulation by the City Council as to the following:

·	utility service;

·	retail rates and charges;

·	standards of service;

·	depreciation,

·	issuance and sale of certain securities; and

·	other matters.

To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to:

·	retail rates and service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;

·	customer service standards;

·	certification of new transmission lines; and

·	extensions of service into new areas.

Entergy Wholesale Commodities

In November 2007, the Board approved a plan to pursue a separation of Entergy’s non-utility nuclear business from Entergy through a spin-off of the business to Entergy shareholders. In July 2010, Entergy withdrew its spin-off transaction petition that was filed with the NYPSC. In August 2010 the NYPSC issued an order closing the proceeding. In the order, the NYPSC also instituted a new proceeding directing Entergy and its subsidiaries with New York nuclear operations (Entergy Corporation, Entergy Nuclear FitzPatrick, LLC, Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, and Entergy Nuclear Operations, Inc., together, the “Entergy Owners”) to show cause why they should not be required to give notice to the NYPSC at least 60 days prior to “any contemplated transactions which could jeopardize the financial strength of any or all of the Entergy New York nuclear subsidiaries.” The facilities to which the order relates are the James A. FitzPatrick Nuclear Station and the Indian Point Energy Center (New York facilities).

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The order states that the intent of the NYPSC is not to impose “an overly broad application” of this notice requirement, and that the NYPSC is “not concerned about transactions that would not jeopardize the financial integrity of New York entities.” By way of example, the order states that the NYPSC is not suggesting that notice be provided “whenever Entergy or an intermediate parent of the New York facilities issues debt, as is often the case, without restrictions being placed on the financial capacity of its New York subsidiaries to borrow or to support debt needed to finance capital projects at the New York facilities.” The order states, however, that the NYPSC may consider an advance notice requirement for any transaction “that would reduce the credit quality of the Entergy Owners below a credit rating of ‘BBB-’ or the equivalent or, in connection with the transaction and in order to provide credit support to a corporate parent, that would restrict a New York facility from issuing its own debt or otherwise require the facility to provide dividend income to its parent, when, in light of the facility’s capital needs, the issuance of such dividends would be inappropriate.”

In September 2010, Entergy filed a response to the NYPSC’s order, which raised a number of concerns with regard to the NYPSC’s jurisdiction to impose the proposed notice requirement and the practical difficulties with implementing such a requirement. In October 2010 the New York Attorney General’s Office filed a response to Entergy’s filing addressing the NYPSC’s jurisdiction to impose the proposed notice requirement, to which Entergy filed a reply. A technical conference was held on February 10, 2011.

Regulation of the Nuclear Power Industry

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend, Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operator of Pilgrim, Indian Point Energy Center, FitzPatrick, Vermont Yankee, and Palisades. Substantial capital expenditures at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.

Nuclear Waste Policy Act of 1982

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2010 of $180.9 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.3 billion.

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The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Moreover, the Obama administration has expressed its intention and taken specific steps to discontinue the Yucca Mountain project and study a new spent fuel strategy. Such actions include a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. However, on June 29, 2010, a panel of the NRC’s Atomic Safety and Licensing Board denied the administration’s motion to withdraw the application. Nevertheless, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear sites.

As a result of the DOE's failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy's nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. In November 2003 these subsidiaries, except for the owner of Palisades, began litigation to recover the damages caused by the DOE's delay in performance. In October 2007, the U.S. Court of Federal Claims awarded $48.7 million jointly to System Fuels and Entergy Arkansas, in damages related to the DOE's breach of its obligations. In a revised decision issued in March 2010, the court awarded $9.7 million jointly to System Fuels, System Energy, and SMEPA. Also in March 2010, in two separate decisions, the court awarded $106.1 million to Entergy Nuclear Indian Point 2, and $4.2 million to Entergy Nuclear Generation Company (the owner of Pilgrim). In September 2010, the court awarded $46.6 million to Entergy Nuclear Vermont Yankee. All of these decisions have been appealed by the DOE to the U.S. Court of Appeals for the Federal Circuit. Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, and at Indian Point and Vermont Yankee in 2008. These facilities will be expanded as needed. Current on-site spent fuel storage capacity at Waterford 3 and Pilgrim is estimated to be sufficient until approximately 2012 and 2014, respectively; by which time dry cask storage facilities are planned to be placed into service at these units.

Nuclear Plant Decommissioning

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Texas, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, the portion of River Bend subject to retail rate regulation, Waterford 3, and Grand Gulf, respectively. These amounts are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.

In 2008, Entergy experienced declines in the market value of assets held in the trust funds for meeting the decommissioning funding assurance obligations for the nuclear plants. This decline adversely affected the affected Entergy subsidiaries’ ability to demonstrate compliance with the NRC’s requirements for providing financial assurance for decommissioning funding for some of its plants. In June 2009, the NRC issued letters indicating that the NRC staff had concluded that there were shortfalls in the amount of decommissioning funding assurance provided for Indian Point 2, Vermont Yankee, Palisades, Waterford 3, and River Bend. The NRC staff subsequently conducted a telephone conference with Entergy on this issue and, in August 2009, Entergy submitted a plan for addressing the identified shortfalls. In its submittal, Entergy provided updated analysis to the NRC indicating that there was no current shortfall in the amounts of the required decommissioning funding assurance for Palisades based upon the trust fund balances as of July 31, 2009 and for Indian Point 2 based upon the trust fund balances as of July 31, 2009 and an analysis of the costs that would be incurred if Entergy elected to use a sixty-year period of safe storage for decommissioning, as permitted by the NRC’s rules. In December 2009 the NRC accepted the analyses regarding Palisades and Indian Point and, with respect to each plant, the NRC concluded that no further action was required. For Vermont Yankee, Entergy concluded that, when using the September 30, 2009 trust fund balance, there was a

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shortfall of approximately $40 million. This $40 million shortfall was satisfied with a $40 million guarantee from Entergy Corporation that was effective as of December 31, 2009. For Waterford 3 and River Bend, Entergy subsidiaries made appropriate filings by December 31, 2009 with their retail regulators that request decommissioning funding from customers to address the shortfalls identified by the NRC. On July 28, 2010, the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend. On December 13, 2010, the PUCT approved increased decommissioning collections for the Texas share of River Bend. Entergy currently believes these approved increases in decommissioning funding will be sufficient to address the shortfalls, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.

Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 17 to the financial statements.

Price-Anderson Act

The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits contingent liability for a single nuclear incident to approximately $117.5 million per reactor (with 104 nuclear industry reactors currently participating). Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities have protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.

Environmental Regulation

Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material adverse effect on their competitive position, results of operations, cash flows or financial position.

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Clean Air Act and Subsequent Amendments

The Clean Air Act and its subsequent amendments established several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:

·	New source review and preconstruction permits for new sources of criteria air pollutants and significant modifications to existing facilities;

·	Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);

·	Nonattainment area programs for control of criteria air pollutants;

·	Hazardous air pollutant emissions reduction program;

·	Interstate Air Transport;

·	Operating permits program for administration and enforcement of these and other Clean Air Act programs; and

·	Regional Haze and Best Available Retrofit Technology programs.

New Source Review (NSR)

Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo a non-routine modification must obtain a permit modification and may be required to install additional air pollution control technologies. Entergy has an established process for identifying modifications requiring additional permitting approval and has followed the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. In recent years, however, the EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine.

In September 2010 the owner of a minority interest in Entergy’s White Bluff and Independence facilities, both located in Arkansas, received a request from the EPA for several categories of information concerning capital and maintenance projects at the facilities in order to determine compliance with the Clean Air Act. It is possible that this request eventually will be referred to Entergy for response as the majority owner and operator. The EPA request for information does not allege that either facility violated the law. In February 2011 Entergy received a similar request from the EPA. Entergy will respond to the information requests as appropriate.

Acid Rain Program

The Clean Air Act provides SO2 allowances to most of the affected Entergy generating units for emissions based upon past emission levels and operating characteristics. Each allowance is an entitlement to emit one ton of SO2 per year. Plant owners are required to possess allowances for SO2 emissions from affected generating units. Virtually all Entergy fossil-fueled generating units are subject to SO2 allowance requirements. Entergy could be required to purchase additional allowances when it generates power using fuel oil. Fuel oil usage is determined by economic dispatch and influenced by the price of natural gas, incremental emission allowance costs, and the availability and cost of purchased power.

Ozone Nonattainment

Entergy Gulf States Louisiana and Entergy Texas each operate fossil-fueled generating units in geographic areas that are not in attainment of the currently-enforced national ambient air quality standards for ozone. The Louisiana nonattainment area that affects Entergy Gulf States Louisiana is the Baton Rouge area. The Texas nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Areas in nonattainment are classified as "marginal," "moderate," "serious," or "severe." When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.

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The Baton Rouge area is classified as a "moderate" nonattainment area for the 8-hour ozone standard, with an attainment date of June 15, 2010. On June 25, 2010, the EPA published a notice in the Federal Register of a proposed determination that the Baton Rouge area has attained the 1997 8-hour ozone standard, but formal redesignation to “attainment” has not been finalized.

The Houston-Galveston-Brazoria area was originally classified as "moderate" nonattainment under the 8-hour standard with an attainment date of June 15, 2010. On June 15, 2007, the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from "moderate" to "severe." On October 1, 2008, the EPA granted the request by the Texas governor to voluntarily reclassify the Houston-Galveston-Brazoria area from a "moderate" 8-hour ozone nonattainment area to a "severe" 8-hour ozone nonattainment area. The EPA also set April 15, 2010, as the date for the State of Texas to submit a revised state implementation plan (SIP) addressing the "severe" ozone nonattainment area requirements of the Clean Air Act. In March 2010 the Texas commission adopted the Houston-Galveston-Brazoria Attainment Demonstration SIP Revision and the Houston-Galveston-Brazoria Reasonable Further Progress SIP Revision for the 1997 eight-hour ozone standard and associated rules. EPA approval is pending. The area's new attainment date for the 8-hour ozone standard is as expeditiously as practicable, but no later than June 15, 2019.

In December 2006, the EPA's revocation of the 1-hour ozone standard was rejected in a judicial proceeding. As a result, numerous requirements can return for areas that fail to meet 1-hour ozone levels by dates set by the law. These requirements include the potential to increase fees significantly for plants operating in these areas. In addition, it is possible that new emission controls may be required. Specific costs of compliance cannot be estimated at this time, but Entergy is monitoring development of the respective state implementation plans and will develop specific compliance strategies as the plans move through the adoption process. The Houston-Galveston-Brazoria area is classified as “severe” nonattainment for 1-hour ozone. However, in February 2010 the EPA published a determination that the Baton Rouge area has reached attainment status for the former 1-hour ozone level. This determination may reduce or eliminate any fees required in the area.

In March 2008, the EPA revised the National Ambient Air Quality Standard for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status. The LDEQ recommended that eleven parishes be designated as nonattainment for the 75 parts per billion ozone standard. Entergy Gulf States Louisiana has two fossil plants and Entergy Louisiana has one fossil plant affected by this recommendation. In Arkansas, the governor recommended that Pulaski County be designated in nonattainment with the new ozone standard, where two of Entergy Arkansas’s smaller facilities are located. These recommendations have not been approved yet by the EPA, and in September 2009 the EPA announced that it is reconsidering the 75 parts per billion standard and may lower it further. Lowering the standard would require additional analysis of county and parish attainment status. On January 7, 2010, the EPA proposed to set the primary 8-hour ozone standard at a level between 60 to 70 parts per billion. The proposal is expected to result in 11 additional Entergy facilities operating

in areas designated as non-attainment for ozone. Following nonattainment designation, states will be required to develop state implementation plans that outline control requirements that will enable the affected counties and parishes to reach attainment status. Entergy facilities in these areas may be subject to installation of NOx controls, but the degree of control will remain unknown until the state implementation plans are developed. Entergy will continue to monitor and engage in the state implementation plan development process in Entergy states.

Hazardous Air Pollutants

The EPA is developing a Maximum Achievable Control Technology (MACT) retrofit standard for new and existing coal and oil-fired units. In 2009 the EPA issued an Information Collection Request to gather data needed for promulgation of Hazardous Air Pollutant regulations. It is currently expected that the EPA will propose a MACT rule for mercury and other hazardous air pollutants in mid-2011 with a final rule by late-2011. Entergy remains involved in the current rulemaking process.

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Interstate Air Transport

In March 2005, the EPA finalized the Clean Air Interstate Rule (CAIR), which is intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule requires a combination of investment of capital to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.

Based on several court challenges, the CAIR was vacated and remanded to EPA by the D.C. Circuit in 2008. The court allowed the CAIR to become effective on January 1, 2009, while the EPA revised the rule. The EPA released the proposed Transport Rule to replace the CAIR on July 9, 2010. The EPA expects to issue the final Transport Rule in late spring 2011. As proposed, the rule will become effective January 2012. Entergy’s capital investment and annual allowance purchase costs under the Transport Rule will depend on the economic assessment of NOx and SO2 allowance markets, the cost of control technologies, generation unit utilization, and the availability and cost of purchased power.

Regional Haze

In June 2005, the EPA issued final Best Available Retrofit Control Technology (BART) regulations that could potentially result in a requirement to install SO2 and NOx pollution control technology on certain of Entergy’s coal and oil generation units. The rule leaves certain BART determinations to the states. The Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the Clean Air Visibility Rule. The ADEQ determined that Entergy Arkansas’s White Bluff power plant affects a Class I Area’s visibility and will be subject to the EPA’s presumptive BART requirements to install scrubbers and low NOx burners. Under then current regulations, the scrubbers would have had to be operational by October 2013. Entergy filed a petition in December 2009 with the Arkansas Pollution Control and Ecology Commission requesting a variance from this deadline, however, because the EPA has not approved Arkansas’s Regional Haze SIP and the EPA has expressed concerns about Arkansas’s Regional Haze SIP and questioned the appropriateness of issuing an air permit prior to that approval. Entergy Arkansas’s petition requested that, consistent with federal law, the compliance deadline be changed to as expeditiously as practicable, but in no event later than five years after EPA approval of the Arkansas Regional Haze SIP. The Arkansas Pollution Control and Ecology Commission approved the variance in March 2010. The timeline for EPA action on the Arkansas Regional Haze SIP is uncertain at this time.

Currently, the White Bluff project is suspended, but Entergy Arkansas estimates that its share of the project could cost approximately $500 million. Entergy Arkansas expects the plant to continue to operate during construction, although an outage would be necessary to complete the tie-in of the scrubbers.

Potential Legislative, Regulatory, and Judicial Developments (Air)

In addition to the specific instances described above, there are a number of legislative and regulatory initiatives relating to the reduction of emissions that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:

·	designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;

introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other gas emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs. Entergy cannot estimate the effect of any future legislation at this time due to the uncertainty of the regulatory format;

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·	efforts to implement a voluntary program intended to reduce carbon dioxide emissions and efforts in Congress to establish a mandatory federal carbon dioxide emission control structure;

·	passage and implementation of the Regional Greenhouse Gas Initiative by several states in the northeast United States and similar actions on the west coast of the United States;

·	efforts on the state and federal level to codify renewable portfolio standards requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources;

·	efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, and stormwater runoff control regulations; and

efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissions and risk. Entergy has prepared responses for the Carbon Disclosure Project’s (CDP) annual questionnaire for the past several years and has given permission for those responses to be posted to CDP’s website.

In addition to these initiatives, certain states and environmental advocacy groups sought judicial action to require the EPA to promulgate regulations under existing provisions of the Clean Air Act to control carbon dioxide emissions from power plants. In April 2007 the U.S. Supreme Court held that the EPA is authorized by the current provisions of the Clean Air Act to regulate emissions of carbon dioxide and other “greenhouse gases” as “pollutants” (Massachusetts v. EPA) and that the EPA is required to regulate these emissions from motor vehicles if the emissions are anticipated to endanger public health or welfare. The Supreme Court directed the EPA to make further findings in this regard. Entergy participated as a friend of the court in Massachusetts v. EPA. Entergy will continue to advocate in support of reasonable market-based regulation of carbon dioxide. Entergy has also supported the comments of various industry groups advocating national legislation to address carbon dioxide emissions instead of attempting to regulate under the provisions of the Clean Air Act. Entergy continues to monitor these and similar actions in order to analyze their potential operational and cost implications and benefits.

In 2009 the EPA published an “endangerment finding” stating that the emission of “greenhouse” gases “may reasonably be anticipated to endanger public health or welfare” and that the emission of these pollutants from mobile sources (such as cars and trucks) contributes to this endangerment. The EPA issued final mobile source emission regulations on April 1, 2010. On April 2, 2010, the EPA issued a policy stating that the regulation of greenhouse gas emissions from mobile sources would, as of January 2, 2011 (the date that the mobile source rule “takes effect”), trigger the regulation of greenhouse gases from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V programs of the Clean Air Act.

In June 2010 the EPA published the final Tailoring Rule outlining the applicability criteria that determine which stationary sources and modification projects become subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. The Tailoring Rule establishes a two-step process for implementing regulation of greenhouse gas emissions under the PSD and Title V programs. The first step, which began on January 2, 2011, limits the applicability of the PSD and Title V requirements for greenhouse gas emissions to sources that are already subject to PSD and Title V based on the emission of non-greenhouse gas pollutants. Specifically, projects undertaken at stationary sources will trigger PSD permitting requirements if the project increases net greenhouse gas emissions by at least 75,000 tons per year carbon dioxide equivalent and significantly increases emissions of at least one non-greenhouse gas pollutant. During step one, only sources subject to Title V based on their emission of non-greenhouse gas pollutants will be required to address greenhouse gas emissions in their Title V permit.

The second step of the Tailoring Rule, which will begin on July 1, 2011, subjects to Title V requirements any new or existing source not already subject to Title V that emits, or has the potential to emit, at least 100,000 tons per year carbon dioxide equivalent. In addition, new sources that have the potential to emit at least 100,000 tons per year carbon dioxide equivalent and significantly modified existing sources that emit or have the potential to emit at least 75,000 tons per year carbon dioxide equivalent will also be subject to PSD requirements.

Both the Endangerment Finding and the Tailoring Rule are subject to pending judicial review. The rules have not been stayed by the court and are in effect pending review.

In anticipation of the potential imposition of carbon dioxide emission limits on the electric industry in the future, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included establishment of a formal program to stabilize power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in actually reducing emissions

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below 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 and 35.6 million tons in 2005. Entergy established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases at 20% below 2000 levels through 2010 and continues to support national legislation that would increase planning certainty for electric utilities while addressing emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low- or non-emitting gas-fired and nuclear generation technologies, Entergy’s overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per kilowatt-hour of electricity generated, is already among the lowest in the industry. In 2006, Entergy changed its method of calculating emissions and now includes emissions from controllable power purchases as well as its ownership share of generation. Total carbon dioxide emissions were approximately 45.0 million tons in 2010.

Greenhouse Gas Reporting

In September 2009, the EPA finalized a rule to require reporting of several greenhouse gases. This rule will require Entergy to report annually greenhouse gas emissions from operating power plants and natural gas distribution operations. Entergy has developed compliance plans, is collecting the necessary data, and will report as required in 2011.

New Source Performance Standards for Greenhouse Gas Emissions

The EPA announced a schedule for establishing new source performance standards (NSPS) for greenhouse gas (GHG) emissions from power plants and refineries. Under the schedule, EPA will issue proposed regulations for power plants by July 26, 2011 and final regulations no later than May 26, 2012. These regulations would establish GHG NSPS for new and modified sources, and emission guidelines for existing sources. Entergy will continue to monitor and be engaged in the rulemaking process.

Clean Water Act

The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.

NPDES Permits and Section 401 Water Quality Certifications

NPDES permits are subject to renewal every five years. Consequently, Entergy is currently in various stages of the data evaluation and discharge permitting process for its power plants. Additionally, the State of New York has taken the position that a new state-issued water quality certification is required as part of the NRC license renewal process. Therefore, Entergy Wholesale Commodities’ Indian Point nuclear facilities in New York also are seeking a section 401 certification prior to license renewal. The FitzPatrick nuclear facility has obtained a section 401 certification.

Indian Point

Entergy is involved in an administrative permitting process with the New York State Department of Environmental Conservation (NYSDEC) for renewal of the Indian Point 2 and Indian Point 3 discharge permits. In November 2003, the NYSDEC issued a draft permit indicating that closed cycle cooling would be considered the “best technology available” for minimizing alleged adverse environmental effects attributable to the intake of cooling water at Indian Point, subject to a feasibility determination and alternatives analysis for that technology, if Entergy applied for and received NRC license renewal for Indian Point 2 and Indian Point 3. Upon becoming effective, the draft permit also would have required payment of approximately $24 million annually, and an annual 42 unit-day outage period, until closed cycle cooling is implemented. Entergy is participating in the administrative process to request that the draft permit be modified prior to final issuance, and opposes any requirement to install cooling towers at Indian Point.

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An August 2008 ruling by the NYSDEC’s Assistant Commissioner has restructured the permitting and administrative process, including the application of a new economic test designed to implement the U.S. Second Circuit Court of Appeals standard in that court’s review of EPA’s cooling water intake structure rules, which is discussed in the 316(b) Cooling Water Intake Structures section below. The NYSDEC has directed Entergy to develop detailed feasibility information regarding the construction and operation of cooling towers, and alternatives to closed cycle cooling, prior to the issuance of a new draft permit by the NYSDEC staff and commencement of the adjudicatory proceeding. The reports include a visual impact and aesthetics report filed in June 2009, a plume and emissions report filed in September 2009, a technical feasibility report filed in February 2010, and an economic report to establish whether the technology, if feasible, satisfies the economic test that is part of the New York standard. Entergy has also requested that the Assistant Commissioner reconsider the New York standard in light of the U.S. Supreme Court decision reversing the Second Circuit’s alternative economic test adopted in the August 2008 ruling. The current procedural schedule calls for hearings on certain issues to commence in 2011 in consolidation with certain issues in the water quality certification matter discussed below. The NYSDEC is expected to consider the information submitted and issue another draft permit with a new best technology available determination, which could still be cooling towers. A new comment period and further contested proceedings likely would follow.

In April 2009, with a reservation of rights regarding the applicability of the section, Entergy’s Indian Point facility submitted a Section 401 water quality certification to the NYSDEC. The certification, or a waiver or exemption of the same, is potentially required pursuant to Section 401 of the Clean Water Act as a supporting document to the NRC’s license renewal decision. In April 2010 the NYSDEC denied Indian Point’s water quality certification concluding that Indian Point’s continued operation during a renewed NRC license period would not comply with existing New York state water quality standards. The denial was a NYSDEC staff decision and Entergy filed comments on this decision and has requested a hearing before a NYSDEC ALJ. The ALJs held a Legislative Hearing (agency public comment session) and an Issues Conference (pre-trial conference) in July 2010 and set certain issues for trial in 2011. After the full hearing on the merits a party to the proceeding can appeal the decision to the Commissioner of the NYSDEC and then to state court. The NYSDEC staff decision does not restrict Indian Point operations, but the issuance of a certification is potentially required prior to NRC issuance of renewed unit licenses.

In the February 2010 feasibility report Entergy provided an updated estimate of the cost to retrofit Indian Point 2 and Indian Point 3 with cooling towers. Construction costs for retrofitting with cooling towers are estimated to be at least $1.19 billion, in addition to lost generation of approximately 14.5 terawatt-hours (TWh) during the estimated 42-week forced outage of both units. Entergy also proposed an alternative to the cooling towers, the use of wedgewire screens, which are currently expected to cost approximately $200 million to $250 million to install. Due to fluctuations in power pricing and because a retrofitting of this size and complexity has never been undertaken at an operating nuclear facility, significant uncertainties exist in these estimates and, therefore, they could be materially higher than estimated.

316(b) Cooling Water Intake Structures

The EPA finalized new regulations in July 2004 governing the intake of water at large existing power plants employing cooling water intake structures. The rule sought to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states challenged various aspects of the rule. In January 2007, the U.S. Second Circuit Court of Appeals remanded the rule to the EPA for reconsideration. The court instructed the EPA to reconsider several aspects of the rule that were beneficial to businesses affected by the rule after finding that these provisions of the rule were contrary to the language of the Clean Water Act or were not

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sufficiently explained in the rule. In April 2008, the U.S. Supreme Court agreed to review the Second Circuit decision on the question of whether the EPA may take into consideration a cost-benefit analysis in developing these regulations, a consideration of potential benefit to businesses affected by the rule that the Second Circuit disallowed. In March 2009, the Supreme Court ruled in favor of the petitioners that cost-benefit analysis may be taken into consideration. The EPA is scheduled to reissue this proposed rule in 2011, with finalization in 2012. The revised rule may be similar in structure to the rule remanded by the Second Circuit, or the EPA may issue a rule with a substantially different structure and effect. Until the EPA issues guidance on what actions should be taken to comply with the Clean Water Act, and until the form and substance of the new rule itself is determined, it is impossible to estimate the effect of the rule on Entergy's business. See the discussion above regarding the Indian Point permitting process under similar New York state provisions of law.

In March 2010 the NYSDEC released a new proposed policy establishing closed cycle cooling as the presumptive performance goal for best technology available (BTA) determinations for cooling water intake structures. The proposed policy applies primarily to electric generating facilities with thermal discharges and capacity factors of greater than fifteen percent that also are designed to withdraw at least 20 million gallons of water per day. If closed cycle cooling is not available for a particular facility because of construction, operational, or other relevant reasons, then the facility must implement an alternative technology that achieves a level of protection for aquatic life that is within ten percent of the expected or projected reductions associated with closed cycle cooling. The NYSDEC would make BTA determinations through the State Pollution Discharge Elimination System (SPDES) permitting program, but BTA decisions would be subject to further review and modification under the State Environmental Quality Review Act. Public comments on the draft policy were due July 9, 2010. Entergy filed comments and will continue to monitor these developments.

At the request of the EPA Region 1 (Boston), Entergy submitted extensive data to the agency in July 2008 concerning cooling water intake impacts at the Pilgrim nuclear power plant. The Engineering Study, included as part of the July 2008 submittal, concluded that cooling towers are not feasible due to restrictions in the plant's condenser design and capacity. Other technologies, such as variable speed pumps and the relocation of the cooling water intake, were also analyzed as part of that submittal. EPA has not yet responded to the July 2008 submittal.

Entergy will continue to monitor the activities of the EPA and the states toward the implementation of section 316(b) of the Clean Water Act. Deadlines for determining compliance with Section 316(b) and for any required capital or operational expenditures are unknown at this time due to the remand of the rule to the EPA. As a result, management cannot predict the amounts Entergy will ultimately be required to spend to comply with Section 316(b) and any related state regulations, although such amounts could be significant.

Coastal Zone Management Act

The Coastal Zone Management Act requires federal activities within a coastal zone to be consistent with the state’s federally-approved coastal zone management program. Therefore, a nuclear facility located within a coastal zone must obtain a consistency certification from the state as part of the NRC’s license renewal process (and other facilities may need determinations from time to time to support other federal permits and licenses, such as wetland dredge or fill permits). Entergy subsidiaries own and operate plants that are within coastal zones.

Pilgrim has received its consistency determination from the Commonwealth of Massachusetts. In New York, the Coastal Management Program promotes waterfront revitalization, protects fish and wildlife habitats, protects and enhances scenic and historic areas, and promotes water access and public recreation. FitzPatrick has obtained its consistency certification. Indian Point expects to file its consistency determination application with the New York Department of State in 2011 or 2012, pending the accumulation of information being developed in other areas, such as the NRC final environmental impact statement associated with its NRC License Renewal Application and the State Environmental Quality Review Act (SEQRA) reports being prepared in the SPDES permit proceedings. When the application is deemed complete, the New York Department of State has six months from the date of the application to issue or deny the consistency certification.

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Generation Facility Effluent Limitations

The EPA selected the steam electric generating sector for the development of effluent guidelines revisions in December 2009. As part of this revision effort, the EPA distributed an information request to certain of the different types of power plants nationwide. Entergy received this questionnaire for several facilities, both fossil and nuclear, and has completed the questionnaires as requested. Entergy will continue to monitor the progress of the effluent guidelines revision efforts by the EPA.

Groundwater at Certain Nuclear Sites

The NRC requires nuclear power plants to regularly monitor and report the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in on site ground water at nuclear plants.

As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Entergy’s FitzPatrick, Indian Point, Palisades, Pilgrim, Grand Gulf and Vermont Yankee plants. Based on current information, the concentrations and locations of tritium detected at these plants pose no threat to public health or safety.

At FitzPatrick, a sample collected from a reactor building perimeter sump in November 2009 showed elevated levels of tritium. Twenty-one monitoring wells are being sampled and analyzed on a periodic basis. Investigations are ongoing to determine the source of the tritium. No elevated levels of tritium have been found in any of the groundwater monitoring wells. The reactor building perimeter sump continues to show low concentrations of tritium.

Entergy identified and addressed two sources of the contamination at Indian Point: the Unit 1 and 2 spent fuel pools. In October 2007, the EPA announced that it was consulting with the NRC and the NYSDEC regarding Indian Point. The EPA stated that after reviewing data it confirmed with New York State that there have been no violations of federal drinking water standards for radionuclides in drinking water supplies. Indian Point has implemented an extensive groundwater monitoring and protection program, including installing approximately 35 monitoring wells. Entergy has been working cooperatively with the NRC and the NYSDEC in a split sample program to independently analyze test samples.

At Palisades, Entergy identified tritium in two groundwater monitoring wells in December 2007 caused by leakage from the buried piping for a recirculation line. Following investigation and repair work on this line, the decision was made to abandon the line and install new, replacement buried pipe for this system. This effort was completed in December 2009. Groundwater from three site monitoring wells has continued to show positive detections of tritium and are being sampled and analyzed on a bi-weekly basis and remaining site monitoring wells are being sampled and analyzed quarterly.

At Pilgrim, 18 monitoring wells are being sampled and analyzed on a routine basis. Results continue to show low levels of tritium. A hydrogeological analysis was performed in 2009 to pinpoint locations for additional evaluation wells, and these wells were installed in 2010. Tritium was discovered in two onsite wells, and stakeholder notifications were made. Investigations are underway to determine the source of the tritium, and split sampling is done routinely with the State of Massachusetts.

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At Grand Gulf, groundwater samples collected in June 2010 revealed the presence of low-level tritium. The detections are believed to be from tritium recapture from atmospheric deposition; however, further analysis and investigation are taking place to determine the cause.

In January 2010, Vermont Yankee was notified by its off-site analytical laboratory that a sample collected from a groundwater monitoring well in mid-November 2009 showed elevated levels of tritium. In March 2010, Vermont Yankee announced that it had identified the source of the tritium leakage at the plant, and that it had stopped the leakage. Remediation of the soil is complete and groundwater remediation is ongoing. In October 2010, Vermont Yankee received lab results confirming the presence of low levels of tritium at concentrations well below the EPA drinking water limit in a former on-site drinking water well. Vermont Yankee had discontinued use of this well as a drinking water source since February 2010. To date no tritium has been detected in the Connecticut River. Both the NRC and the Vermont Department of Health have stated that tritium at the Vermont Yankee facility has not been a threat to public health and safety. In January 2011 periodic sample results from two wells detected the presence of tritium at concentrations below regulatory reporting requirements. Additional investigation is ongoing.

In February 2010 the Vermont Public Service Board (VPSB) began a proceeding to conduct an investigation into whether Vermont Yankee should be required to cease operations, or take other ameliorative actions, pending completion of repairs to stop releases of tritium or other radionuclides into the environment. This investigation will also consider whether good cause exists to modify or revoke the Vermont Yankee certificate of public good that the VPSB issued in 2002 and whether any penalties should be imposed on Vermont Yankee for any identified violations of Vermont statutes or VPSB orders related to those releases. The proceeding and VPSB investigation were opened prior to Vermont Yankee locating the source and beginning the remediation of the tritium leaking into groundwater at the site. The VPSB conceded in its order that its jurisdiction to impose some or all of the relief requested may be preempted by federal law or regulation, and the parties were asked to brief preemption issues during the initial phase of the proceeding. Initial and reply briefs on the issue of the VPSB’s jurisdiction were filed by the parties, including Vermont Yankee, in August and September 2010. The VPSB held evidentiary hearings in January 2011 on the facts of the tritium leakage and remediation and on various parties’ requests for relief. Initial and reply post-hearing briefs are due in February 2011. There is no schedule for decision by the VPSB on jurisdiction or other issues.

Indian Point Units 1 and 2 Hazardous Waste Remediation

As part of the effort to terminate the current Indian Point 2 mixed waste (waste that is regulated as both low-level nuclear waste and hazardous waste) storage permit, Entergy was required to perform groundwater and soil sampling for metals, PCBs and other non-radiological contaminants on plant property, regardless of whether these contaminants stem from onsite activities or were related to the waste stored on-site pursuant to the permit. Entergy believes this permit is no longer necessary for the facility due to an exemption for mixed wastes promulgated as part of the EPA’s hazardous waste regulations. This exemption allows mixed waste to be regulated through the NRC license instead of through a separate EPA or state hazardous waste permit. In February 2008, Entergy submitted its report on this sampling effort to the NYSDEC. The report indicated the presence of various metals in soils at levels above the NYSDEC cleanup objectives. It does not appear that these metals are connected to operation of the nuclear facility. At the request of the NYSDEC, Entergy submitted a plan in August 2008 for a study that will identify the sources of the metals. The NYSDEC approved this work plan with some conditions related to the need to study whether the soil impact observed may have originated from plant construction materials. This issue is being studied by Entergy to determine if any changes to the work plan are necessary. The NYSDEC may require additional work to define the vertical and lateral extent of the contamination on-site, and evaluate any potential for migration off-site. The NYSDEC plans to use the results of this investigation to determine whether the permit can be terminated and the metals left in place until plant decommissioning or if further investigation or remediation is required. Entergy is unable to determine what the extent or cost of required remediation, if any, will be at this time.

Prior to Entergy’s purchase of Indian Point Unit 1, the previous owner completed the cleanup and desludging of the Unit 1 water storage pool, generating mixed waste. The waste currently is stored in the Unit 1 containment building in accordance with NRC regulations controlling low level radioactive waste. The waste is also regulated by the NYSDEC. The NYSDEC requires a quarterly survey of the availability of any commercial facility capable of

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treating, processing, and disposing of this waste in a commercially reasonable manner. Entergy continues to review this matter and to conduct its quarterly searches for a commercially reasonable vendor that is acceptable both to the NRC and the NYSDEC. The cost of this disposal cannot be estimated at this time due to the many variables existing in the type and manner of disposal.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint and several liability on responsible parties. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of CERCLA liabilities that are not de minimis are discussed in the “Other Environmental Matters” section below.

Coal Combustion Residuals

In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contains two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of RCRA Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially used would remain excluded from hazardous waste regulation.

The proposed regulations would create new compliance requirements including modified storage, new notification and reporting practices, new financial assurance requirements, and product disposal considerations. According to EPA estimates, the annualized cost of on-site disposal under the two proposals would be $3.6 million to $9 million for the White Bluff and Independence facilities and $1.7 million to $3.3 million for the Nelson Unit 6 facility. If Entergy utilized off-site disposal, which it would not plan to do, the EPA’s total cost estimates for disposal of CCRs under Subtitle C regulation ranges from $250 to $350 million per year.

Other Environmental Matters

Entergy Gulf States Louisiana and Entergy Texas

Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Gulf States, Inc. and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States, Inc.’s premises (see “Litigation” below).

Entergy Gulf States Louisiana is currently involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, was apparently routed to a portion of the property for disposal. The same area has also been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform removal action at the site. In 2002, approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003, a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005, an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006 and is continuing on a quarterly basis. Entergy Gulf States Louisiana and Entergy Texas each believe that its remaining responsibility for this site will not materially exceed the existing clean-up provisions of $0.3 million for Entergy Gulf States Louisiana and $0.2 million for Entergy Texas.

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In 1994, Entergy Gulf States, Inc. performed a site assessment in conjunction with a construction project at the Louisiana Station Generating Plant (Louisiana Station). In 1995, a further assessment confirmed subsurface soil and groundwater impact to three areas on the plant site. After validation, a notification was made to the LDEQ and a phased process was executed to remediate each area of concern. The final phase of groundwater clean-up and monitoring at Louisiana Station is expected to continue for several more years. Future costs are not expected to exceed Entergy Gulf States Louisiana’s existing provision of $0.7 million.

Entergy Louisiana and Entergy New Orleans

Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Louisiana and Entergy New Orleans and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Louisiana’s and Entergy New Orleans’s premises (see “Litigation” below).

During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. Entergy Louisiana has determined that some of its power plant wastewater impoundments were affected by these regulations and may require remediation, repair, or closure. Completion of this work is dependent on pending LDEQ approval of submitted solid waste permit applications. As a result, a recorded liability in the amount of $1.9 million for Entergy Louisiana existed at December 31, 2010 for ongoing wastewater remediation and repairs and closures. Management believes this reserve to be adequate based on current estimates.

Transmission and distribution storm teams entered wetland areas of Lafourche Parish to restore Entergy Louisiana’s Barataria-Golden Meadow line shortly after Hurricane Katrina. A portion of this line crosses property owned by a third party. The landowner requested that Entergy Louisiana conduct extensive wetland mitigation over a ten-acre area and has filed suit against Entergy Louisiana and certain other Entergy subsidiaries concerning the extent of the mitigation. Entergy Louisiana believed that the marsh area affected by its activities is less than 2 acres and that restoration could be conducted to the satisfaction of the U. S. Corps of Engineers and the State of Louisiana for substantially less than the over $4 million claimed by the plaintiff. Entergy Louisiana resolved all outstanding claims with the landowner for less than $2 million, including any claims arising from previous work on the property.

Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas

The TCEQ notified Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are PRPs concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination exists at the site. Entergy Gulf States, Inc. and Entergy Louisiana sent transformers to this facility during the 1980s. Entergy Gulf States Louisiana, Entergy Texas, Entergy Louisiana, and Entergy Arkansas responded to an information request from the TCEQ and continue to cooperate in this investigation. Entergy Gulf States Louisiana, Entergy Texas, and Entergy Louisiana joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site, while Entergy Arkansas and Entergy New Orleans likely will pay de minimus amounts. Current estimates, although preliminary and variable depending on the level of third-party cost contributions, indicate that Entergy’s total share of remediation costs likely will be less than $1 million. The TCEQ

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approved an agreed administrative order in September 2006 that allows the implementation of a Remedial Investigation/Feasibility Study at the SESCO site; with the ultimate disposition being a remedial action to remove contaminants of concern. The TCEQ approved the Remedial Investigation Work Plan in May 2007 and field sampling began in July 2007. Off-site removal activities of PCB-impacted soil and debris initiated at the site in August 2010.

Entergy Mississippi, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas

The EPA has notified Entergy Mississippi, Entergy Gulf States Louisiana, Entergy Texas, and Entergy New Orleans that the EPA believes those entities are PRPs concerning contamination of an area known as “Devil’s Swamp Lake” near the Port of Baton Rouge, Louisiana. The area allegedly was contaminated by the operations of Rollins Environmental (LA), Inc, which operated a disposal facility to which many companies contributed waste. Documents provided by the EPA indicate that Entergy Louisiana may also be a PRP. Entergy continues to monitor this developing situation.

Entergy

In November 2010 a transformer at the Indian Point facility failed, resulting in a fire and the release of non-PCB oil to the ground surface. The fire was extinguished by the facility’s fire deluge system. No injuries occurred due to the transformer failure or company response. An undetermined amount of oil and water were released into the facility’s discharge canal and the environment surrounding the transformer and discharge canal, including the Hudson River, as a result of the failure, fire, and fire suppression. Once the fire was extinguished, Indian Point personnel and contractors began recovering free product from the damaged transformer, the transformer containment moat, and the area surrounding the transformer. Additional remedial work continues, and the State of New York may assess a penalty due to the release of oil to waters of the state and the failure of the transformer containment moat to prevent this release of oil. Discussions with the state continue.

Litigation

Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.

Ratepayer and Fuel Cost Recovery Lawsuits (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Entergy New Orleans Fuel Adjustment Clause Litigation

In April 1999 a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs sought treble damages for alleged injuries arising from the defendants’ alleged violations of Louisiana’s antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans’s fuel adjustment filings with the City Council. In the fourth quarter 2010, Entergy reached a settlement agreement with the plaintiffs that ended the proceeding. The settlement did not materially affect Entergy’s results of operations, financial position, or cash flows.

Entergy New Orleans Rate of Return Lawsuit

In April 1998 a group of residential and business ratepayers filed a complaint against Entergy New Orleans in state court in Orleans Parish purportedly on behalf of all ratepayers in New Orleans. The plaintiffs alleged that Entergy New Orleans overcharged ratepayers in violation of limits on Entergy New Orleans’s rate of return that the plaintiffs allege were established by ordinances passed by the City Council in 1922. In the fourth quarter 2010, Entergy reached a settlement agreement with the plaintiffs that ended the proceeding. The settlement did not materially affect Entergy’s results of operations, financial position, or cash flows.

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Texas Power Price Lawsuit

In August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class apparently of the Texas retail customers of Entergy Gulf States, Inc. who were billed and paid for electric power from January 1, 1994 to the present. The named defendants include Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., and Entergy Arkansas. Entergy Gulf States, Inc. was not a named defendant, but is alleged to be a co-conspirator. The court granted the request of Entergy Gulf States, Inc. to intervene in the lawsuit to protect its interests.

Plaintiffs allege that the defendants implemented a “price gouging accounting scheme” to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting and/or reselling to off-system utilities less expensive power offered and/or purchased from off-system suppliers and/or generated by the Entergy system. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.

Plaintiffs stated in their pleadings that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys’ fees, and disgorgement of profits. The plaintiffs’ experts have tendered a report calculating damages in a large range, from $153 million to $972 million in present value, under various scenarios. The Entergy defendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs’ expert reports.

The case is pending in state district court, and the court has not set a date for a class certification hearing.

Mississippi Attorney General Complaint

The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The litigation is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. On December 29, 2008, the defendant Entergy companies filed to remove the attorney general’s suit to U.S. District Court (the forum that Entergy believes is appropriate to resolve the types of federal issues raised in the suit), where it is currently pending, and additionally answered the complaint and filed a counter-claim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. The Mississippi attorney general has filed a pleading seeking to remand the matter to state court. In May 2009, the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint.

Fiber Optic Cable Litigation (Entergy Corporation and Entergy Louisiana)

Several property owners have filed a class action suit against Entergy Louisiana, Entergy Services, ETHC, and Entergy Technology Company in state court in St. James Parish, Louisiana purportedly on behalf of all property owners in Louisiana who have conveyed easements to the defendants. The lawsuit alleges that Entergy installed fiber optic cable across the plaintiffs’ property without obtaining appropriate easements. The plaintiffs seek damages equal to the fair market value of the surplus fiber optic cable capacity, including a share of the profits made through use of the fiber optic cables, and punitive damages. Entergy removed the case to federal court in New Orleans; however, the district court remanded the case back to state court. In February 2004, the state court entered an order certifying this matter as a class action. Entergy’s appeals of this ruling were denied. The parties have entered into a term sheet establishing basic terms for a settlement that must be approved by the court.

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Asbestos Litigation (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Numerous lawsuits have been filed in federal and state courts primarily in Texas and Louisiana, primarily by contractor employees who worked in the 1940-1980s timeframe, against Entergy Gulf States Louisiana and Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos. Many other defendants are named in these lawsuits as well. Currently, there are approximately 500 lawsuits involving approximately 5,000 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position or results of operation of the Utility operating companies.

Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees. Generally, the amount of damages being sought is not specified in these proceedings. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board; claims of retaliation; and claims for or regarding benefits under various Entergy Corporation sponsored plans. Entergy and the Registrant Subsidiaries are responding to these suits and proceedings and deny liability to the claimants.

Employees

Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2010, Entergy subsidiaries employed 14,958 people.

Utility:
Entergy Arkansas		1,411
Entergy Gulf States Louisiana		816
Entergy Louisiana		964
Entergy Mississippi		773
Entergy New Orleans		345
Entergy Texas		694
System Energy		-
Entergy Operations		2,901
Entergy Services		3,148
Entergy Nuclear Operations		3,791
Other subsidiaries		115
Total Entergy		14,958

Approximately 5,500 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, Fire Professionals of America.

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Availability of SEC filings and other information on Entergy’s website

Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The public may read and copy any materials that Entergy files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.

Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy's website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include our annual and quarterly reports on Forms 10-K and 10-Q (including related filings in XBRL format) and current reports on Form 8-K; our proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy's Investor Relations website free of charge. Entergy is providing the address to its Internet site solely for the information of investors and does not intend the address to be an active link or to otherwise incorporate the contents of the website into this report.

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RISK FACTORS

Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy's financial condition, results of operations and liquidity. See "FORWARD-LOOKING INFORMATION."

Utility Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and System Energy)

The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that are lengthy and subject to appeal that could result in delays in effecting rate changes and uncertainty as to ultimate results.

The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance charges, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment.

In addition, regulators can initiate proceedings to investigate the prudence of costs in the Utility operating companies' base rates and examine, among other things, the prudence of the companies' operation and maintenance practices, level of expenditures (including storm costs), allowed rates of return and appropriate rate base, proposed resource acquisitions and previously incurred capital expenditures. The regulators can disallow costs found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. The proceedings generally have long timelines, are primarily based on historical costs, and may or may not be limited by statute, which could cause the Utility operating companies and System Energy to experience regulatory lag in recovering such costs through rates. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. Although four of the Utility operating companies currently obtain recovery under formula rate plans, at some point in the future these formula rate plans may no longer be extended, at which time these Utility operating companies would operate again in a more traditional rate case environment.

The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, which could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to certain of the Utility operating companies, see Note 2 to the financial statements.

The Utility operating companies recover fuel and purchased power costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.

The Utility operating companies recover their fuel and purchased power costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs. Regulators can initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies.

The Utility operating companies' cash flows can be negatively affected by the time delays between when gas, power or other commodities are purchased and the ultimate recovery from customers of the purchased costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period's fuel and purchased power

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costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power recovery, see Note 2 to the financial statements.

As a result of a challenge by the LPSC, the manner in which the Utility operating companies have traditionally shared the costs associated with coordinated planning, construction and operation of generating resources has been changed by the FERC, which will require adjustment of retail and wholesale rates in the jurisdictions where the Utility operating companies provide service and has introduced additional uncertainty in the ratemaking process.

The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. In 2005, the FERC issued a decision requiring changes to the cost allocation methodology used in that rate schedule.

The LPSC, APSC, MPSC and the AEEC have appealed the 2005 FERC decision to the Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit affirmed the FERC's decision in most respects, but remanded the case to the FERC for further proceedings and reconsideration of its conclusion that it was prohibited from ordering refunds and its determination to implement the bandwidth remedy commencing with calendar year 2006 production costs (with the first payments/receipts commencing in June 2007), rather than commencing the remedy on June 1, 2005. The D.C. Circuit concluded the FERC had failed to offer a reasoned explanation regarding these issues.

In 2007 through 2010, payments were made by Entergy Arkansas to certain of the Utility operating companies in compliance with the 2005 FERC decision on the cost allocation methodology. There have been challenges to the level of payments made by Entergy Arkansas under the FERC’s decision and the prudence of the Utility operating companies’ production costs. The ability to recover in rates any changes to the cost allocation resulting from the challenges, and timing of such recovery, is uncertain and could be the subject of additional regulatory and other proceedings. For information regarding these and other proceedings associated with the System Agreement, as well as additional information regarding the System Agreement itself, see Note 2 to financial statements, System Agreement Cost Equalization Proceedings. The outcome and timing of this FERC proceeding and resulting recovery and impact on rates cannot be predicted at this time.

There is uncertainty as to the timing or form of any successor arrangement to the System Agreement and the effect of such arrangement (or absence thereof) will have on Entergy and the Utility operating companies.

Based upon the effect of the FERC decision described in the preceding risk factor undermining the benefits of continued participation in the System Agreement, in December 2005, Entergy Arkansas provided notice of its intent to terminate its participation in the System Agreement. In November 2007, Entergy Mississippi provided its notice to terminate its participation in the System Agreement. Each notice of termination is effective ninety-six (96) months from the date of notice (December 2013 for Entergy Arkansas and November 2015 for Entergy Mississippi) or such earlier date as authorized by the FERC. The FERC accepted the notices in November 2009; the LPSC and City Council have requested rehearing of that order. In February 2011, the FERC denied the request for rehearing. Entergy cannot predict the timing or the form of any successor arrangement to the System Agreement, or in the alternative, participation in a regional transmission organization (RTO), and the effect such arrangement (or the absence thereof) will have on Entergy or the Utility operating companies.

For further information regarding the FERC and APSC proceedings see “Rate, Cost-recovery, and Other Regulation – Federal Regulation – System Agreement” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.

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(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

A delay or failure in recovering amounts for storm restoration costs incurred, as a result of severe weather could have material adverse effects on Entergy and those Utility operating companies affected by severe weather.

Entergy's and its Utility operating companies' results of operations, liquidity and financial condition can be materially adversely affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material adverse effect on Entergy and those Utility operating companies affected by severe weather.

The arrangement for the operation of the Utility operating companies’ transmission system faces regulatory challenges and uncertainty in connection with the scheduled expiration of the current Independent Coordinator of Transmission arrangement in November 2012.

In 2000, the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of an independent RTO. In November 2006, the Utility operating companies installed the SPP as their Independent Coordinator of Transmission (ICT) with responsibility for certain transmission tariff functions, including granting or denying transmission service, administering OASIS, evaluating all transmission requests, and serving as the reliability coordinator. The initial term of the ICT was for four years and in November 2010 the FERC approved an extension of the ICT arrangement for two years, or until November 2012. In its order issued in March 2009 pertaining to a requested modification regarding the weekly procurement process (WPP) through the ICT arrangement, the FERC imposed conditions related to the ICT arrangement and indicated it wanted an evaluation of the success of the ICT arrangement and transmission access on the Entergy transmission system. In compliance with the FERC’s March 2009 order, the Utility operating companies filed with the FERC a process for evaluating the modification or replacement of the current ICT arrangement. An Entergy Regional State Committee (E-RSC), comprised of one representative from each of the Utility operating companies’ retail regulators has been formed and, in concert with the FERC, has requested a cost/benefit analysis of comparing the ICT arrangement to a proposal under which Entergy would join the SPP RTO. The scope of the study was expanded to consider Entergy joining the Midwest ISO RTO as another alternative. On September 30, 2010, the retained consultant presented its cost/benefit analysis of Entergy and Cleco regions joining the SPP RTO. The cost/benefit analysis indicates that the Entergy region, including entities beyond the Utility operating companies, would realize a net cost of $438 million to a net benefit of $387 million, primarily depending upon transmission cost allocation issues. Addendum studies, including studies related to Entergy Arkansas and the Utility operating companies joining the Midwest ISO, are to be completed by the end of the first quarter 2011. For further information regarding the FERC and proceedings related to the ICT, see “Rate, Cost-recovery, and Other Regulation - Federal Regulation -Independent Coordinator of Transmission” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.

There is uncertainty as to whether a successor ICT arrangement or alternative such as joining an RTO will have received regulatory approval and whether corresponding changes to cost recovery mechanisms will be in place prior to the termination of the current ICT arrangement in November 2012. To the extent successor ICT arrangements or alternatives have not been approved, an extension of the current ICT arrangement may be required. The outcome of any effort to negotiate an extension of the current arrangement or to make alternative arrangements cannot be predicted at this time.

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Nuclear Operating and Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially adversely affect Entergy's and their results of operations, financial condition and liquidity.

Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors. For the Utility operating companies that own nuclear plants, lower capacity factors increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Although most of the Entergy Wholesale Commodities nuclear forward sales are on a pure unit-contingent basis, which depends on the availability of the asset, some of the unit-contingent contracts guarantee a specified minimum capacity factor. In the event these plants were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk if capacity factors decrease.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities’ nuclear plant owners periodically shutdown their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy's and their results of operations, financial condition and liquidity could be materially adversely affected.

Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months and have historically averaged approximately 30 days in duration. Plant maintenance and upgrades are often scheduled during such planned outages. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease and maintenance costs may increase. Entergy Wholesale Commodities’ nuclear plants may face lower margins due to higher costs and lower energy sales for unit-contingent power supply contracts or potentially higher energy replacement costs for unit-contingent contracts with capacity guarantees that are not met due to extended or unplanned outages.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment and fabrication), and the risk of being unable to effectively manage these risks by purchasing from a diversified mix of sellers located in a diversified mix of countries could materially adversely affect Entergy's and their results of operations, financial condition and liquidity.

Based upon currently planned fuel cycles, Entergy's nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2011. Entergy's ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the creditworthiness and performance reliability of uranium miners, as well as upon the structure of Entergy's contracts for the purchase of nuclear fuel. There are a number of possible alternate suppliers that may be accessed to mitigate unexpected supply disruption events, including potentially drawing upon Entergy's own inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any such alternate uranium supply from the market will be

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dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price increases could materially adversely affect the liquidity, financial condition and results of operations of certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities.

Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations or suspend or revoke their licenses, which could materially adversely affect Entergy's and their results of operations, financial condition and liquidity.

Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially adversely affect the results of operations, liquidity or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies or System Energy. Events at nuclear plants owned by others, as well as those owned by one of these companies, may cause the NRC to initiate such actions. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially adversely affect the financial condition, results of operations and liquidity of Entergy, certain of the Utility operating companies, System Energy or Entergy Wholesale Commodities.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially adversely affect Entergy's and their results of operations, financial condition and liquidity.

The nuclear generating units owned by certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, could result in reduced profitability. Operations at any of the nuclear generating units owned and operated by Entergy's subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet supply commitments and penalties for failure to perform under their contracts with customers. Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy's nuclear power plants that may need to be replaced or refurbished. This dependence on a reduced number of suppliers could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.

The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel storage facility, as well as interim storage and transportation requirements.

Certain of the Utility operating companies, System Energy and the owners of the Entergy Wholesale Commodities nuclear plants incur costs on a periodic basis for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the storage of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the Obama administration has cut the budget for the Yucca Mountain project, and has made various statements that Yucca Mountain will not be the solution for spent fuel storage. These actions may prolong the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE plans to commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at its nuclear sites. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository for spent nuclear fuel may affect the

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ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the "Critical Accounting Estimates – Nuclear Decommissioning Costs -- Spent Fuel Disposal” section of Management's Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy.

Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material adverse effect on Entergy's and their results of operations, financial condition or liquidity.

Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner's public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool of up to approximately $117.5 million per reactor. With 104 reactors currently participating, this translates to a total public liability cap of approximately $12.2 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers (currently $375 million for each operating site). Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the $375 million in primary insurance coverage, each owner of a nuclear plant reactor, including Entergy's Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the $375 million primary level, up to a maximum of $117.5 million per reactor per incident (Entergy's maximum total contingent obligation per incident is $1.3 billion). The retrospective premium payment is currently limited to $17.5 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $117.5 million cap.

NEIL is a utility industry mutual insurance company, owned by its members. All member plants could be subject to assessments (retrospective premium of up to 10 times current annual premium for all policies) should the surplus (reserve) be significantly depleted due to insured losses. As of April 1, 2010, the maximum assessment amounts total $72.7 million for Nuclear South plants and $89.3 million for the Nuclear Northeast plants. Retrospective Premium Insurance available through NEIL’s reinsurance treaty can cover the potential assessments. The Nuclear Northeast plants currently maintain the Retrospective Premium Insurance to cover this potential assessment.

As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition or liquidity of Entergy, certain of the Utility operating companies, System Energy or the Entergy Wholesale Commodities subsidiaries.

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Market performance and other changes may decrease the value of assets in the decommissioning trusts, which then could require significant additional funding.

Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections are based upon operating license lives as well as estimated trust fund earnings and decommissioning costs. In connection with the acquisition of certain nuclear plants, the Entergy Wholesale Commodities plant owners also acquired decommissioning trust funds that are funded in accordance with NRC regulations. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds. As part of the Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades/Big Rock Point purchases, the former owners transferred decommissioning trust funds, along with the liability to decommission the plants, to the respective Entergy Wholesale Commodities nuclear power plant owners. As part of the Indian Point 1 and 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplemental decommissioning trust fund. As part of the Palisades transaction, the Entergy Wholesale Commodities business assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Once the spent fuel is removed from the site, the Entergy Wholesale Commodities business will dismantle the spent fuel storage facility and complete site decommissioning. The Entergy Wholesale Commodities business expects to fund this activity from operating revenue, and Entergy is providing $5 million in credit support to provide financial assurance to the NRC for this obligation.

In 2008, Entergy experienced declines in the market value of assets held in the trust funds for meeting its decommissioning funding assurance obligations for its plants. This decline adversely affected Entergy’s ability to demonstrate compliance with the NRC’s requirements for providing financial assurance for decommissioning funding for some of its plants, which deficiencies have now been corrected. An early plant shutdown, poor investment results (including results from poor performance of or volatility in the capital markets such as occurred in 2008) or higher than anticipated decommissioning costs could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Entergy Wholesale Commodities nuclear plant owners may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. For further information regarding nuclear decommissioning costs, see the "Critical Accounting Estimates – Nuclear Decommissioning Costs" section of Management's Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy and Note 9 to the financial statements.

New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation of Entergy’s nuclear power plants.

New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where five of the six units in the current fleet of Entergy Wholesale Commodities nuclear power plants are located. These concerns have led to, and are expected to continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy's subsidiaries own nuclear generating units for legislative and regulatory changes that could lead to the shut-down of nuclear units, denial of license renewal applications, municipalization of nuclear units, restrictions on nuclear units as a result of unavailability of sites for spent nuclear fuel storage and disposal, or other adverse effects on owning and operating nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material adverse effect on Entergy's results of operations, financial condition and liquidity.

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(Entergy Corporation)

A failure to obtain renewed licenses for the continued operation of the Entergy Wholesale Commodities nuclear power plants could have a material adverse effect on Entergy's results of operations, financial condition, and liquidity and could lead to an increase in depreciation rates or an acceleration of the timing for the funding of decommissioning obligations.

The license renewal and related processes for the Entergy Wholesale Commodities nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The operating licenses for Vermont Yankee, Pilgrim, Indian Point 2 and Indian Point 3 expire in March 2012, June 2012, September 2013 and December 2015, respectively. Various parties have expressed opposition to renewal of these licenses. Renewal of the Indian Point licenses is the subject of ongoing proceedings before the Atomic Safety and Licensing Board (ASLB) of the NRC. Certain contentions have been admitted for litigation and new and amended contentions filed by parties in January and February 2011 have not been acted upon by the ASLB. Hearings on the contentions admitted by the ASLB currently are expected to begin in early 2012. The ASLB has completed its proceedings regarding Vermont Yankee, but the New England Coalition filed a new contention, which the ASLB denied in October 2010. The New England Coalition requested NRC review of the denial in November 2010. Finally, with respect to the Pilgrim license renewal, the NRC has issued decisions resolving all but one of the issues that were previously appealed by Pilgrim Watch. The NRC remanded one issue to the ASLB, which ordered that testimony be filed in January 2011 and scheduled a hearing for March 9, 2011. Pilgrim Watch filed two new contentions, one of which it subsequently amended, in December 2010 and January 2011. The ASLB for Pilgrim have not decided whether to admit or deny the new contentions.

In relation to Indian Point 2 and Indian Point 3, the New York Department of Environmental Conservation has taken the position that these plant owners must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. For the Indian Point plants, the Entergy Wholesale Commodities plant owners also must obtain a Coastal Zone Management Act consistency determination from the New York Department of State prior to getting the renewed licenses. For further information regarding these environmental regulations see “Environmental Regulation, Clean Water Act” in Part I, Item 1.

Pursuant to Vermont law, Vermont Yankee is subject to state approvals to continue operations that are independent of NRC license renewal. Under state law, there is a two-step state law licensing process for obtaining a certificate of public good to continue to operate Vermont Yankee and store newly generated spent fuel after March 21, 2012. First, the Vermont legislature must vote affirmatively to permit the Vermont Public Service Board to consider Vermont Yankee’s application for a renewed certificate of public good for the continued operation of Vermont Yankee and for storage of spent fuel. Second, the Vermont Public Service Board must vote to renew the certificate of public good. The Entergy Wholesale Commodities affiliates that own and operate Vermont Yankee filed an application with the Vermont Public Service Board in March 2008 to renew its certificate of public good to operate for 20 years beginning March 22, 2012 and to store spent nuclear fuel generated after that date. Ten days of hearings were held in May and June 2009. The Department of Public Service and other parties contended during the hearing that a favorable power purchase agreement for the sale of power from Vermont Yankee to Vermont utilities would be important to demonstrating that renewal of the certificate of public good promoted the public interest. Proceedings in that docket currently are in abeyance.

During its 2009 session, which concluded in May, several committees of the Vermont General Assembly held hearings on Vermont Yankee, but no bill or resolution was introduced for approval of continued operation and storage of spent nuclear fuel generated after March 21, 2012. In January 2010, the Governor of the State of Vermont issued a statement indicating he would not ask the Vermont General Assembly to consider the renewal of a certificate of public good during its 2010 session, based on the discovery of tritium leakage from Vermont Yankee, concerns about miscommunication by Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations related to underground piping at Vermont Yankee carrying radionuclides, and other issues including decommissioning. Nevertheless, on February 24, 2010, a bill to authorize the Public Service Board to approve the continued operation of Vermont Yankee was defeated in the Vermont Senate by a vote of 26 to 4. Neither house of the Vermont General Assembly has voted on a similar bill since that time.

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If the NRC finally denies the applications for the renewal of operating licenses for one or more of the Entergy Wholesale Commodities nuclear power plants, or a state in which any such nuclear power plant is located does not take actions legally required for the continued operation of such plant, Entergy’s results of operations, financial condition, and liquidity could be materially adversely affected by loss of revenue and cash flow associated with the plant or plants, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal. For further discussion regarding the license renewal processes for the Entergy Wholesale Commodities’ nuclear power plants, see “ENTERGY’S BUSINESS – Entergy Wholesale Commodities – Property – Nuclear Generating Stations” in Part I, Item 1 for Entergy Corporation and its subsidiaries.

The decommissioning trust fund assets for the nuclear power plants owned by Entergy Wholesale Commodities’ nuclear plant owners may not be adequate to meet decommissioning obligations if one or more of their nuclear power plants is retired earlier than the anticipated shutdown date or if current regulatory requirements change which then could require additional funding.

Under NRC regulations, Entergy’s nuclear subsidiaries are permitted to project the NRC-required decommissioning amount based on an NRC formula and the amount in each of the Entergy Wholesale Commodities nuclear power plant's decommissioning trusts combined with other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process for each of these nuclear power plants, with the earliest scheduled shutdown being Vermont Yankee in 2012. As a result, if the projected amount of our decommissioning trusts exceeds the NRC-required decommissioning amount, then its decommissioning obligations are considered to be funded in accordance with NRC regulations. In the event the NRC's formula does not sufficiently reflect the actual costs the applicable Entergy subsidiaries would be required to incur to decommission these nuclear power plants, and funding is otherwise inadequate, or if the formula is changed to require increased funding, additional resources would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.

With respect to the decommissioning trusts for Vermont Yankee, Indian Point 2 and Palisades, the total amount in each of those trusts as of December 31, 2010 would not have been sufficient to initiate and complete the immediate near-term decommissioning of the respective unit as of such date, but rather the funds would have been sufficient to place the unit in a condition of safe storage status pending future completion of decommissioning. For example, if an Entergy subsidiary had decided to shutdown and immediately begin decommissioning one of those nuclear power plants on December 31, 2010, its trust funds for the plant would have been insufficient and the applicable Entergy subsidiary would have been required to rely on other capital resources to fund the entire decommissioning obligations unless the completion of decommissioning could be deferred during some number of years of safe storage status (as is permitted by NRC regulations). Thus, if an Entergy subsidiary decides to shutdown one of these nuclear power plants earlier than the scheduled shutdown date and conduct a prompt decommissioning, the applicable Entergy subsidiary may be unable to rely upon only the decommissioning trust to fund the entire decommissioning obligations, which would require it to obtain funding from other sources.

Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of Entergy Wholesale Commodities’ nuclear power plants. As a result, under any of these circumstances, Entergy's results of operations, liquidity and financial condition could be materially adversely affected.

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Entergy Wholesale Commodities’ nuclear power plants are exposed to price risk through either advance sale of energy and capacity into forward markets or accepting spot prices primarily in day-ahead markets.

Entergy and its subsidiaries are not guaranteed any rate of return on their capital investments in non-utility businesses. In particular, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. As of December 31, 2010, Entergy Wholesale Commodities nuclear power generation plants had sold forward 96%, 87%, 40%, 25% and 15% of its generation portfolio's planned energy output for 2011, 2012, 2013, 2014 and 2015, respectively. Many of the Entergy Wholesale Commodities business’s existing long-term contracts expire by the end of 2012. The obligations under most of these agreements are contingent on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also

a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. For those obligations that are not unit-contingent, Entergy Wholesale Commodities may be required to make payments to the purchaser based on the difference between the market price at the delivery point and the contract price at times when the unit being hedged is not running, and to the extent market prices are higher than contract prices, the amount of such payments could be substantial.

Market prices may fluctuate substantially sometimes over relatively short periods of time and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules and other mechanisms to address volatility and other issues in these markets.

The price that different counterparties offer for forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities' contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition or liquidity. The recent economic downturn and negative trends in the energy commodity markets have resulted in lower natural gas prices, and current prevailing market prices for electricity in the New York and New England power regions are therefore generally below the prices of Entergy Wholesale Commodities’ existing contracts in those regions. To the extent these market conditions persist, Entergy Wholesale Commodities’ realized price per MWh can be expected to continue to decline. With operating licenses for Vermont Yankee, Pilgrim, Indian Point 2 and Indian Point 3 expiring between 2012 and 2015, delays in obtaining extension of the operating licenses and any other approvals required for continued operation of the plants, Entergy Wholesale Commodities may enter into fewer unit-contingent forward sales contracts for output from such plants for periods beyond the license expiration. Instead, in order to hedge future price risk to desired levels, Entergy Wholesale Commodities may enter into firm LD forward sales contacts under which it will be exposed to operational price risk to the extent that the plants do not run as expected.

Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy's control to a significant degree, are:

·	prevailing market prices for natural gas, uranium (and its conversion, enrichment and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;

·	seasonality;

·	availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;

·	changes in production and storage levels of natural gas, lignite, coal and crude oil and refined products;

·	liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term;

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·	the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;

·	electricity transmission, competing generation or fuel transportation constraints, inoperability or inefficiencies;

·	the general demand for electricity, which may be significantly affected by national and regional economic conditions;

·	weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;

·	the rate of growth in demand for electricity as a result of population changes, regional economic conditions and the implementation of conservation programs;

·	regulatory policies of state agencies that affect the willingness of Entergy Wholesale Commodities nuclear customers to enter into long-term contracts generally, and contracts for energy in particular;

increases in supplies due to actions of current Entergy Wholesale Commodities nuclear competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities and improvements in transmission that allow additional supply to reach Entergy Wholesale Commodities’ nuclear markets;

·	union and labor relations;

·	changes in Federal and state energy and environmental laws and regulations and other initiatives, including but not limited to, the price impacts of proposed emission controls such as the Regional Greenhouse Gas Initiative (RGGI); and

·	natural disasters, terrorist actions, wars, embargoes and other catastrophic events.

The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

The Entergy Wholesale Commodities business is subject to extensive federal, state and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause the Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.

Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants, as well as Entergy Nuclear Power Marketing, LLC, is a "public utility" under the Federal Power Act by virtue of making wholesale sales of electric energy. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities charges for power from its facilities.

The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business' generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state and local laws and regulation applicable to the Entergy Wholesale Commodities business, see “Entergy’s Business-Regulation of Entergy’s Business” in Part I, Item 1 for Entergy Corporation and its subsidiaries.

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The regulatory environment applicable to the electric power industry has undergone substantial changes over the past several years as a result of restructuring initiatives at both the state and federal levels. These changes are ongoing and Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism and have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, as well as proposals to re-regulate the markets, impose a generation tax or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued or delayed, the Entergy Wholesale Commodities business' results of operations, financial condition and liquidity could be materially adversely affected.

The nuclear power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material adverse effect on Entergy's results of operations, financial condition or liquidity.

Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets. In particular, the assets of the Entergy Wholesale Commodities business, including the nuclear power plants, are subject to impairment if adverse market conditions arise and continue (such as declines in market prices for electricity), if adverse regulatory events occur (including with respect to environmental regulation), if a unit ceases operation or if a unit's operating license is not renewed. Moreover, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows or a decline in observable industry market multiples could all result in potential impairment charges for the affected assets.

As discussed elsewhere in this Form 10-K, the operating licenses for Vermont Yankee, Pilgrim, Indian Point 2 and Indian Point 3 expire between 2012 and 2015 and are currently the subject of license renewal processes at the NRC and the states in which the plants operate. If Entergy concludes that any of these nuclear power plants is unlikely to operate significantly beyond its current license expiration date, which conclusion would be based on a variety of factors, such a conclusion could result in an impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the nuclear power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material adverse effect on Entergy's results of operations, financial condition or liquidity.

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General Business Risks

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy and its subsidiaries' ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.

Entergy's business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy's and the Utility operating companies' liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy's service territory with Hurricane Katrina and Hurricane Rita in 2005 and Hurricane Gustav and Hurricane Ike in 2008. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, higher than expected pension contributions, an acceleration of payments or decreased credit lines, less cash flow from operations than expected or other unknown events, such as future storms, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy and the Utility operating companies, which in turn could negatively affect access to the capital markets.

The global capital and credit markets experienced extreme volatility and disruption in the fourth quarter of 2008 and much of 2009. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries' ability to maintain and to expand their businesses. Events beyond Entergy's control, such as the volatility and disruption in global capital and credit markets in 2008 and 2009, may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation's ability to sustain its current common stock dividend level.

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

A downgrade in Entergy Corporation's or its subsidiaries' credit ratings could negatively affect Entergy Corporation's and its subsidiaries' ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments or repay certain indebtedness.

There are a number of factors that rating agencies evaluate to arrive at credit ratings for Entergy Corporation and the Registrant Subsidiaries, including the ability to cover liquidity requirements, the availability of committed external credit support, and Entergy Corporation's share repurchase program, dividend policy and other commitments for capital. If one or more rating agencies downgrade Entergy Corporation's, any of the Utility operating companies', or System Energy's ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases and other agreements.

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Most of Entergy Corporation's and its subsidiaries' large customers, suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation's or its subsidiaries' ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2010, based on power prices at that time, Entergy had credit exposure of $14 million under the guarantees in place supporting Entergy Nuclear Power Marketing (an Entergy Wholesale Commodities subsidiary) transactions, $20 million of guarantees that support letters of credit, and $3 million of posted cash collateral. As of December 31, 2010, the credit exposure associated with Entergy Wholesale Commodities assurance requirements could increase by $123 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets. In the event of a decrease in Entergy Corporation's credit rating to below investment grade, based on power prices as of December 31, 2010, Entergy would have been required to provide approximately $78 million of additional cash or letters of credit under some of the agreements.

The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial conditions, results of operations or liquidity of Entergy and the Utility operating companies could be materially adversely affected.

Entergy's and the Utility operating companies' ability to complete construction of power generation facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, the inability to raise capital on favorable terms, downward changes in the economy and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business may occur that may materially affect the schedule, cost and performance of these projects. If these projects are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-off of the investment in the project. For further information regarding capital expenditure plans and other uses of capital in connection with the potential construction of additional generation supply sources within the Utility operating companies' service territory, and as to the Entergy Wholesale Commodities business, see the "Capital Expenditure Plans and Other Uses of Capital" section of Management's Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.

The Utility operating companies, System Energy and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to, environmental and other matters.

The businesses in which the Utility operating companies, System Energy and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy and the Entergy Wholesale Commodities business manage air emissions, discharges to water, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties' claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy and the Entergy Wholesale Commodities business are subject to liability under

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these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy and the Entergy Wholesale Commodities business and of property contaminated by hazardous substances they generate. The Utility operating companies are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.

Emissions of nitrogen and sulfur oxides, mercury, particulates, and other regulated air contaminants from generating plants are potentially subject to increased regulation, controls and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, sometimes resulting in large-scale changes to anticipated regulatory regimes. Risks relating to global climate change and initiatives to compel CO2 emission reductions are discussed below.

Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the "Regulation of Entergy's Business – Environmental Regulation" section of Part I, Item 1.

The Utility operating companies, System Energy and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.

Entergy's business is subject to extensive and mandatory reliability standards. Such standards, which are established by the North American Electric Reliability Corporation (NERC) and the SERC Reliability Corporation (SERC), are approved by the FERC and frequently are reviewed, amended and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system. Entergy has notified the SERC of potential violations of certain NERC reliability standards, including certain Critical Infrastructure, Protection Facility Connection and System Protection Coordination standards. Entergy is working with the SERC to provide information concerning these potential violations. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities business.

(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

The effects of weather and economic conditions and the related impact on electricity and gas usage, may materially adversely affect the Utility operating companies' results of operations.

Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues. As a corollary, moderate temperatures tend to decrease usage of energy and resulting revenues. Seasonal pricing differentials, coupled with higher consumption levels, typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions or storms, however, may stress the Utility operating companies' generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. These extreme conditions could have a material adverse effect on the Utility operating companies' financial condition, results of operations and liquidity.

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Industrial sales volume was depressed in the latter part of 2008 and through most of 2009, in part because the overall economy declined, with lower usage across the industrial sector affecting both the large customer industrial segment as well as small and mid-sized industrial customers. Despite the apparently improving economic conditions in the service territories of the Utility operating companies since the fourth quarter 2009, it is possible that continued or recurrent poor economic conditions, combined with increasing rates in certain of the Utility operating companies' service territories, could result in slower or declining sales growth and increased bad debt expense relative to recent years, which could materially adversely affect Entergy's and the Utility operating companies' results of operations, financial condition and liquidity.

The effects of climate change and environmental and regulatory obligations intended to compel CO2 emission reductions could materially adversely affect the financial condition, results of operations and liquidity of Entergy and the Utility operating companies.

In an effort to address climate change concerns, Federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court's 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other "greenhouse gases" under the Clean Air Act, the EPA, various environmental interest groups and other organizations are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. In 2010, EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units, and additional new source performance standards are expected in 2012. Developing and implementing plans for compliance with CO2 emissions reduction requirements can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. Violations of such requirements may subject Entergy and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties' claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy's regulators and, in extreme cases, Entergy's regulators might deny or defer timely recovery of these costs. Future changes in environmental regulation governing the emission of CO2 and other "greenhouse gases" could make some of Entergy's electric generating units uneconomical to maintain or operate, and could increase the difficulty that Entergy and its subsidiaries have with obtaining or maintaining required environmental regulatory approvals, which could also materially adversely affect the financial condition, results of operations and liquidity of Entergy and the Utility operating companies. In addition, several lawsuits currently are pending against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits seek injunctive relief, monetary compensation, and punitive damages.

In addition to the regulatory and financial risks associated with climate change discussed above, physical risks from climate change include an increase in sea level, wetland and barrier island erosion, risks of flooding and changes in weather conditions, such as changes in precipitation, average temperatures and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes.

These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System's ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material adverse effect on Entergy's and the Utility operating companies' financial condition, results of operations and liquidity.

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Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially adversely affect Entergy's and its subsidiaries' results of operations, financial condition and liquidity.

To manage their near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements and inventories of natural gas, uranium (and its conversion), coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially adversely affect Entergy's and its subsidiaries' results of operations and financial position.

Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations or financial position.

Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy's or its subsidiaries' credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy's or its subsidiaries' liquidity and financial position.

The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially adversely affect the Utility operating companies and Entergy Wholesale Commodities.

The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries might be forced to act on the credit support provided and acquire alternative hedging arrangements or draw on the credit support provided by the counterparties, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy's lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially adversely affect the adequacy of its liquidity sources.

The Wall Street Transparency and Accountability Act of 2010 and rules and regulations promulgated under the act may adversely affect the ability of the Utility operating companies and the Entergy Wholesale Commodities business to utilize certain commodity derivatives for hedging and mitigating commercial risk.

The Wall Street Transparency and Accountability Act of 2010, which was enacted on July 21, 2010 as part of the Dodd-Frank Act Wall Street Reform and Consumer Protection Act, and the rules and regulations to be promulgated under the act will impose governmental regulation on the over-the-counter derivative market, including the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business to hedge and mitigate commercial risk. Under the act, certain swaps will be subject to mandatory clearing and exchange trading requirements. Swap dealers and major participants in the swap market will be subject to capital, margin, registration, reporting, recordkeeping and business conduct requirements with respect to their swap activities. Position limits will also apply to certain swaps activities. The act requires the applicable regulators, which in the case of commodity swaps will be the Commodity Futures Trading Commission, to engage in substantial rulemaking in order to implement the provisions of the act and such rulemaking is not yet final. Both the Utility operating companies

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and the Entergy Wholesale Commodities business currently utilize commodity swaps to hedge and mitigate commodity price risk. It is not known whether the act and regulations promulgated under the act will have an adverse effect upon the market for the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business. However, to the extent that the act and regulations promulgated under the act have the effect of increasing the price of such commodity swaps or limiting or reducing the availability of such commodity swaps, whether through the imposition of additional capital, margin or compliance costs upon market participants or otherwise, the financial performance of the Utility operating companies and/or the Entergy Wholesale Commodities business may be adversely affected. To the extent that the Utility operating companies and the Entergy Wholesale Commodities business would be required to post margin in connection with existing or future commodity swaps in addition to any margin currently posted by such entities, such entities may need to secure additional sources of capital to meet such liquidity needs or cease utilizing such commodity swaps.

Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding.

The performance of the capital markets affects the values of the assets held in trust under Entergy's pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy's benefit plan liabilities. The recent recession and volatility in the capital markets have affected the market value of these assets, which may affect Entergy's planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy's pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. Guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act of 2006 as a result of these discussions and efforts may affect the level of Entergy's pension contributions in the future. For further information regarding Entergy's pension and other postretirement benefit plans, reference is made to the "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" section of Management's Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.

The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.

Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. States in which the Utility operating companies operate, in particular Louisiana, Mississippi and Texas, have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.

Terrorist attacks, future war or risk of war may adversely affect Entergy's results of operations.

As power generators and distributors, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, including physical and cyber attacks, either as a direct act against one of Entergy's generation facilities, an act against the transmission and distribution infrastructure used to transport power which affects its ability to operate or an act against the information technology systems and network infrastructure of Entergy and its subsidiaries.

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Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite the implementation of security measures by Entergy and its subsidiaries, all technology systems are vulnerable to disability, failures or unauthorized access due to such activities. If Entergy’s or its subsidiaries’ technology systems were to fail or be breached and be unable to recover in a timely way, Entergy or its subsidiaries may be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised.

If any such attacks were to occur, Entergy's and the Utility operating companies’ business, financial condition and results of operations could be materially adversely affected. The risk of attacks also may cause Entergy and the Utility operating companies to incur increased capital and operating costs to implement increased security for its nuclear power plants and other facilities, such as additional physical facility security and additional security personnel, and for systems to protect its information technology and network infrastructure systems.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’ and System Energy’s results of operations, financial condition and liquidity.

Entergy and its subsidiaries make judgments regarding the potential tax effects of various financial transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use and employment-related taxes. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy's, the Utility operating companies' and System Energy's results of operations, financial condition and liquidity. For further information regarding Entergy's accounting for tax obligations, reference is made to Note 3 to the financial statements.

(Entergy Gulf States Louisiana and Entergy New Orleans)

The effect of higher purchased gas cost charges to customers may adversely affect Entergy Gulf States Louisiana's and Entergy New Orleans' results of operations and liquidity.

Gas rates charged to customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy Gulf States Louisiana or Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges are affected by the amount of gas sold to customers. Purchased gas cost charges, which comprise most of a customer's bill and may be adjusted quarterly, represent gas commodity costs that Entergy Gulf States Louisiana or Entergy New Orleans recovers from its customers. Entergy Gulf States Louisiana's or Entergy New Orleans' cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs. When purchased gas cost charges increase substantially reflecting higher gas procurement costs incurred by Entergy Gulf States Louisiana or Entergy New Orleans, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy Gulf States Louisiana or Entergy New Orleans.

(System Energy)

System Energy owns and operates a single nuclear generating facility, and it is dependent on affiliated companies for all of its revenues.

System Energy's operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to receive capacity and energy and are payable on a full cost-of-service basis only so long as Grand Gulf remains in commercial operation. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which is currently due to expire on November 1, 2024. System Energy's financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. For information regarding the Unit Power Sales Agreement and certain other

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agreements relating to the Entergy System companies' support of System Energy (including the Capital Funds Agreement), see the "Grand Gulf - Related Agreements" section of Note 8 to the financial statements and the "Utility - System Energy and Related Agreements" section of Part I, Item 1.

(Entergy Corporation)

Entergy Corporation's holding company structure could limit its ability to pay dividends.

Entergy Corporation is a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation's ability to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The payments of dividends or distributions to Entergy Corporation by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Provisions in the organizational documents, indentures for debt issuances, and other agreements of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends to Entergy Corporation. For further information regarding dividend or distribution restrictions to Entergy Corporation, reference is made to the "COMMON EQUITY – Retained Earnings and Dividend Restrictions" section of Note 7 to the financial statements.

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MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2010 Compared to 2009

Net income increased $105.7 million primarily due to higher net revenue, a lower effective income tax rate, higher other income, and lower depreciation and amortization expenses, partially offset by higher other operation and maintenance expenses.

2009 Compared to 2008

Net income increased $19.7 million primarily due to lower other operation and maintenance expenses and a lower effective income tax rate, partially offset by lower net revenue, higher depreciation and amortization expenses, higher nuclear refueling outage expenses, and higher interest expense.

Net Revenue

2010 Compared to 2009

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2010 to 2009.

		Amount
		(In Millions)

2009 net revenue		$1,102.4
Volume/weather		84.2
Provision for regulatory proceedings		26.1
Retail electric price		16.1
2009 capitalization of Ouachita Plant service charges		12.5
ANO decommissioning trust		(24.4)
Net wholesale revenue		(12.2)
Other		12.0
2010 net revenue		$1,216.7

The volume/weather variance is primarily due to an increase of 2,078 GWh, or 10%, in billed electricity usage. Usage in the industrial sector increased primarily in the small industrial customers segment, as well as in the petroleum refining, chemicals, industrial inorganic, and pulp and paper industries, reflecting strong sales growth on continuing signs of economic recovery. The effect of more favorable weather was the primary driver of the increase in residential and commercial sales.

The provision for regulatory proceedings variance is primarily due to provisions recorded in 2009. See Note 2 to the financial statements for a discussion of regulatory proceedings affecting Entergy Arkansas.

The retail electric price variance is primarily due to a base rate increase effective July 2010, partially offset by the recovery in 2009 of 2008 extraordinary storm costs, as approved by the APSC, which ceased in January 2010. The recovery of storm costs is offset in other operation and maintenance expenses. See Note 2 to the financial statements for more discussion of the rate case settlement and the 2008 extraordinary storm costs.

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Management’s Financial Discussion and Analysis

In 2009, Entergy Arkansas capitalized $12.5 million of Ouachita Plant service charges that were previously expensed. The result of the capitalization in 2009 was a decrease in net revenues with an offsetting decrease in other operation and maintenance expenses.

The ANO decommissioning trust variance is primarily related to the deferral of investment gains from the ANO 1 and 2 decommissioning trust. The gains resulted in an increase in interest and investment income and a corresponding increase in regulatory charges with no effect on net income in accordance with regulatory treatment.

The net wholesale revenue variance is primarily due to reduced margin on wholesale contracts including lower capacity billings to an affiliate for the Ouachita unit that was later purchased by the affiliate in November 2009, and lower margins on co-owner contracts, somewhat offset by lower wholesale energy costs.

Gross operating revenues and fuel and purchased power expenses

Gross operating revenues decreased primarily due to:

·	a decrease of $98.6 million in rider revenues primarily due to lower System Agreement payments in 2010;

·	a decrease of $95.6 million in fuel cost recovery revenues due to a change in the energy cost recovery rider rate change effective April 2010; and

·	a decrease of $72.5 million in gross wholesale revenue due to decreased sales to affiliated customers and the expiration of a wholesale customer contract in 2009.

The decrease was offset by volume/weather, as discussed above.

Fuel and purchased power expenses decreased primarily due to a decrease in the average market price of purchased power.

2009 Compared to 2008

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2009 to 2008.

		Amount
		(In Millions)

2008 net revenue		$1,117.9
Provision for regulatory proceedings		(26.1)
Volume/weather		(24.4)
Retail electric price		26.5
Other		8.5
2009 net revenue		$1,102.4

The volume/weather variance is primarily due to the effect of less favorable weather and an 11.6% volume decrease in industrial sales primarily in the mid to small customer class.

The retail electric price variance is primarily due to the recovery of 2008 extraordinary storm costs as approved by the APSC, effective January 2009, which is discussed in Note 2 to the financial statements. Also contributing to the increase are increases in the capacity acquisition rider related to the Ouachita acquisition. The net income effect of the Ouachita plant cost recovery is limited to a portion representing an allowed return on equity with the remainder offset by Ouachita plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes.

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Gross operating revenues and fuel and purchased power expenses

Gross operating revenues decreased primarily due to:

·	a decrease of $119.9 million in gross wholesale revenue due to a decrease in the average price of energy available for resale sales;

·	a decrease of $63.2 million in fuel cost recovery revenues due to a change in the energy cost recovery rider effective April 2009 and decreased usage; and

·	the volume/weather discussed above.

The decrease was offset by an increase of $90.7 million in rider revenues.

Fuel and purchased power expenses decreased primarily due to a decrease in the average market price of purchased power.

Other Income Statement Variances

2010 Compared to 2009

Other operation and maintenance expenses increased primarily due to:

an increase of $21.7 million in compensation and benefits costs, resulting from decreasing discount rates, the amortization of benefit trust asset losses, and an increase in the accrual for incentive-based compensation. See Note 11 to the financial statements for further discussion of benefits costs;

·	an increase of $6.2 million in vegetation and maintenance expenses; and

·	an increase of $5.4 million in nuclear expenses primarily due to higher labor costs, higher materials costs, and additional projects.

The increase was partially offset by a decrease of $19.4 million due to 2008 storm costs which were deferred per an APSC order and were recovered through revenues in 2009.

Depreciation and amortization expenses decreased primarily due to a decrease in depreciation rates as a result of the rate case settlement agreement approved by the APSC in June 2010.

Other income increased primarily due to the investment gains on the ANO 1 and 2 decommissioning trust discussed above in net revenue.

2009 Compared to 2008

Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the planned maintenance and refueling outage at ANO 1 which ended in December 2008 and the planned maintenance and refueling outage at ANO 2 which ended in September 2009.

Other operation and maintenance expenses decreased primarily due to:

the write off in the fourth quarter 2008 of $52 million of costs previously accumulated in Entergy Arkansas’s storm reserve and $16 million of removal costs associated with the termination of a lease, both in connection with the December 2008 Arkansas Court of Appeals decision in Entergy Arkansas’s 2006 base rate case. The 2006 base rate case is discussed in more detail in Note 2 to the financial statements;

·	the capitalization in 2009 of $12.5 million of Ouachita service charges previously expensed in 2008;

prior year storm damage charges as a result of several storms hitting Entergy Arkansas’s service territory in 2008, including Hurricane Gustav and Hurricane Ike in the third quarter 2008. Entergy Arkansas discontinued regulatory storm reserve accounting beginning July 2007 as a result of the APSC order issued in Entergy Arkansas’s rate case. As a result, non-capital storm expenses of $41 million were charged to other operation and maintenance expenses. In December 2008, $19.4 million of these storm expenses were deferred per an APSC order and were recovered through revenues in 2009; and

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Management’s Financial Discussion and Analysis

·	a decrease of $10.8 million in payroll-related and benefits costs.

The decrease was partially offset by the following:

·	an increase of $17.9 million due to higher fossil costs primarily due to a full year of Ouachita costs in 2009 and higher fossil plant outage costs in 2009;

·	an increase of $14.4 million due to the reinstatement of storm reserve accounting effective January 2009;

·	an increase of $9.6 million in nuclear expenses primarily due to increased nuclear labor and contract costs;

·	an increase in legal expenses as a result of a reimbursement in April 2008 of $7 million of costs in connection with a litigation settlement; and

·	an increase of $4.0 million in customer service costs primarily as a result of write-offs of uncollectible customer accounts.

Depreciation and amortization expenses increased primarily due to an increase in plant in service.

Interest expense increased primarily due to an increase in long-term debt outstanding as a result of the issuance of $300 million of 5.40% Series first mortgage bonds in July 2008.

Income Taxes

The effective income tax rates for 2010, 2009, and 2008 were 39.6%, 55.0%, and 67.2%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2010, 2009, and 2008 were as follows:

		2010	2009	2008
		(In Thousands)

Cash and cash equivalents at beginning of period		$86,233	$39,568	$212

Cash flow provided by (used in):
	Operating activities	512,260	384,192	460,251
	Investing activities	(413,180)	(281,512)	(608,501)
	Financing activities	(79,211)	(56,015)	187,606
	Net increase in cash and cash equivalents	19,869	46,665	39,356

Cash and cash equivalents at end of period		$106,102	$86,233	$39,568

Operating Activities

Cash flow from operations increased $128.1 million in 2010 compared to 2009 primarily due to an increase in net revenue as discussed above, ice storm spending in 2009, and the collection of previously under-recovered fuel costs through the normal operation of the energy cost recovery rider. The increase was offset by an increase of $112 million in pension contributions, and an increase of $65 million in income tax payments. See “Critical Accounting Estimates” below for a discussion of qualified pension and other postretirement benefits funding. In 2010 Entergy Arkansas made tax payments in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The payments result from the reversal of temporary differences for which Entergy Arkansas previously received cash tax benefits and from estimated federal income tax payments for tax year 2010.

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Management’s Financial Discussion and Analysis

Cash flow from operations decreased $76.1 million in 2009 compared to 2008 primarily due to income tax payments of $1.4 million in 2009 compared to income tax refunds of $57.9 million in 2008 and an increase in storm spending in 2009, partially offset by a decrease of $14.1 million in pension contributions.

Investing Activities

Net cash flow used in investing activities increased $131.7 million in 2010 compared to 2009 primarily due to:

·	the sale of one-third of the Ouachita plant for $75 million in 2009;

·	proceeds from the sale/leaseback of nuclear fuel of $118.6 million in 2009. See Note 18 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entity effective January 1, 2010; and

·	increases in nuclear construction expenditures primarily due to the ANO 1 reactor coolant pump upgrade project and security upgrades.

The increase was offset by a decrease in distribution construction expenditures as a result of an ice storm hitting Entergy Arkansas’s service territory in the first quarter 2009.

Net cash flow used in investing activities decreased $327.0 million in 2009 compared to 2008 primarily due to the purchase of the Ouachita plant for $210 million in September 2008 and the sale of one-third of the plant for $75 million in 2009, decreases in nuclear construction expenditures resulting from various nuclear projects that occurred in 2008, and decreases in distribution and transmission construction expenditures resulting from Hurricane Gustav and Hurricane Ike in 2008. The decrease was partially offset by an increase in distribution construction expenditures as a result of an ice storm hitting Entergy Arkansas’s service territory in the first quarter 2009.

Financing Activities

Net cash flow used in financing activities increased $23.2 million in 2010 compared to 2009 primarily due to:

·	retirements of $450 million of first mortgage bonds in 2010;

·	retirements of $139.5 million of pollution control bonds in 2010; and

·	an increase of $125.1 million in common stock dividends paid in 2010.

The increase was offset by:

·	issuances of $575 million of first mortgage bonds in 2010; and

·	the issuance in August 2010 of $124.1 million of storm cost recovery bonds by Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas.

Entergy Arkansas’s financing activities used $56.0 million of cash in 2009 compared to providing $187.6 million in 2008 primarily due to:

·	issuance of $300 million of first mortgage bonds in July 2008;

·	an increase of $23.4 million in common stock dividends paid in 2009; and

·	money pool activity.

Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $77.9 million in 2008.

See Note 5 to the financial statements for details of long-term debt.

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Management’s Financial Discussion and Analysis

Capital Structure

Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table.

	December 31, 2010	December 31, 2009

Debt to capital	55.9%	54.0%
Effect of excluding the securitization bonds	(1.6)%	0.0%
Debt to capital, excluding securitization bonds (1)	54.3%	54.0%
Effect of subtracting cash	(1.5)%	(1.2)%
Net debt to net capital, excluding securitization bonds (1)	52.8%	52.8%

(1)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition.

Uses of Capital

Entergy Arkansas requires capital resources for:

·	construction and other capital investments;

·	debt and preferred stock maturities;

·	working capital purposes, including the financing of fuel and purchased power costs; and

·	dividend and interest payments.

Following are the amounts of Entergy Arkansas’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations:

	2011	2012-2013	2014-2015	after 2015	Total
	(In Millions)
Planned construction and capital investment (1):
Generation	$119	$483	N/A	N/A	$602
Transmission	103	152	N/A	N/A	255
Distribution	122	251	N/A	N/A	373
Other	13	40	N/A	N/A	53
Total	$357	$926	N/A	N/A	$1,283
Long-term debt (2)	$118	$486	$190	$2,128	$2,922
Capital lease payments	$-	$0.5	$0.5	$1	$2
Operating leases	$23	$43	$40	$13	$119
Purchase obligations (3)	$635	$1,211	$929	$1,946	$4,721

(1)	Includes approximately $211 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth.
(2)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(3)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.

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In addition, Entergy Arkansas currently expects to contribute approximately $107.1 million to its pension plans and approximately $26.3 million to other postretirement plans in 2011; although the required pension contributions will not be known with more certainty until the January 1, 2011 valuations are completed by April 1, 2011.

Also in addition to the contractual obligations, Entergy Arkansas has $40.3 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

The planned capital investment estimate for Entergy Arkansas reflects capital required to support existing business and customer growth. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, changes in project plans, the ability to access capital, and the outcome of Entergy Arkansas’s exit from the Entergy System Agreement (which is discussed in “System Agreement” in the “Rate, Cost-recovery, and Other Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis). Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.

As a wholly-owned subsidiary, Entergy Arkansas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly. Entergy Arkansas’s long-term debt indentures restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2010, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $458 million.

White Bluff Coal Plant Project

In June 2005 the EPA issued final Best Available Retrofit Control Technology (BART) regulations that could potentially result in a requirement to install SO2 and NOx pollution control technology on certain of Entergy’s coal and oil generation units. The rule leaves certain BART determinations to the states. The Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the Clean Air Visibility Rule. The ADEQ determined that Entergy Arkansas’s White Bluff power plant affects a Class I Area’s visibility and will be subject to the EPA’s presumptive BART requirements to install scrubbers and low NOx burners. Under then current regulations, the scrubbers would have had to be operational by October 2013. Entergy filed a petition in December 2009 with the Arkansas Pollution Control and Ecology (APC&E) Commission requesting a variance from this deadline, however, because the EPA has not approved Arkansas’s Regional Haze SIP and the EPA has expressed concerns about Arkansas’s Regional Haze SIP and questioned the appropriateness of issuing an air permit prior to that approval. Entergy Arkansas’s petition requested that, consistent with federal law, the compliance deadline be changed to as expeditiously as practicable, but in no event later than five years after EPA approval of the Arkansas Regional Haze SIP. The APC&E Commission approved the variance at its March 26, 2010 meeting. No party appealed the variance, and the ruling is final. The timeline for EPA action on the Arkansas Regional Haze SIP is uncertain at this time.

Currently, the White Bluff project is suspended, but Entergy Arkansas estimates that its share of the project could cost approximately $500 million. The plant would continue to operate during construction, although an outage would be necessary to complete the tie-in of the scrubbers. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates are likely to change based on the results of this continuing analysis.

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Management’s Financial Discussion and Analysis

Ouachita Power Plant

Entergy Arkansas filed with the APSC in September 2007 for its approval of the Ouachita plant acquisition, including full cost recovery. In June 2008 the APSC approved Entergy Arkansas’s acquisition of the Ouachita plant and approved recovery of the acquisition and ownership costs through a rate rider. The APSC also approved the planned sale of one-third of the capacity and energy to Entergy Gulf States Louisiana. Entergy Arkansas purchased the Ouachita plant in September 2008.

In August 2008, the LPSC issued an order approving an uncontested settlement between Entergy Gulf States Louisiana and the LPSC Staff authorizing Entergy Gulf States Louisiana’s purchase, under a life-of-unit agreement, of one-third of the capacity and energy from the 789 MW Ouachita power plant. The LPSC’s approval was subject to certain conditions, including a study to determine the costs and benefits of Entergy Gulf States Louisiana exercising an option to purchase one-third of the plant (Unit 3) from Entergy Arkansas. In April 2009, Entergy Gulf States Louisiana made a filing with the LPSC seeking approval of Entergy Gulf States Louisiana exercising its option to convert its purchased power agreement into the ownership interest in Unit 3 and a one-third interest in the Ouachita common facilities. In September 2009 the LPSC, pursuant to an uncontested settlement, approved the acquisition and a cost recovery mechanism. Entergy Gulf States Louisiana purchased Unit 3 and a one-third interest in the Ouachita common facilities for $75 million in November 2009.

Sources of Capital

Entergy Arkansas’s sources to meet its capital requirements include:

·	internally generated funds;

·	cash on hand;

·	debt or preferred stock issuances; and

·	bank financing under new or existing facilities.

Entergy Arkansas may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:

2010	2009	2008	2007
(In Thousands)

$41,463	$28,859	$15,991	($77,882)

In May 2007, $1.8 million of Entergy Arkansas’s receivable from the money pool was replaced by a note receivable from Entergy New Orleans. See Note 4 to the financial statements for a description of the money pool.

In April 2010, Entergy Arkansas renewed its credit facility through April 2011 in the amount of $75.125 million. There were no outstanding borrowings under the Entergy Arkansas credit facility as of December 31, 2010.

Entergy Arkansas has obtained short-term borrowing authorization from the APSC under which it may borrow through October 2011, up to the aggregate amount, at any one time outstanding, of $250 million. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. Entergy Arkansas has also obtained an order from the APSC authorizing long-term securities issuances through December 2012.

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Entergy Arkansas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

State and Local Rate Regulation

Retail Rates

2009 Base Rate Filing

2006 Base Rate Filing

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance, because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.

See Note 2 to the financial statements and Entergy Corporation and Subsidiaries “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement” for discussions of the System Agreement proceedings.

Energy Cost Recovery Rider

Entergy Arkansas’s retail rates include an energy cost recovery rider. In early October 2005, the APSC initiated an investigation into Entergy Arkansas's interim energy cost recovery rate. The investigation focused on Entergy Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006, the APSC extended its investigation to cover the costs included in Entergy Arkansas's March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.

In January 2007, the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy

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Management’s Financial Discussion and Analysis

Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas's assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas's petition for rehearing and for stay of the APSC order.

In October 2008, Entergy Arkansas filed a motion to lift the stay and to rescind the APSC's January 2007 order in light of the arguments advanced in Entergy Arkansas's rehearing petition and because the value for Entergy Arkansas's customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. In December 2008, the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas's rehearing request and of the unresolved issues in the proceeding. The APSC ordered the parties to submit their unresolved issues list in the pending proceeding, which the parties did. In February 2010 the APSC denied Entergy Arkansas's request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.

Storm Cost Recovery

Entergy Arkansas January 2009 Ice Storm

In January 2009, a severe ice storm caused significant damage to Entergy Arkansas’s transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. In June 2010, the APSC issued a financing order authorizing the issuance of storm cost recovery bonds, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. See Note 5 to the financial statements for additional discussion of the issuance of the storm cost recovery bonds.

Federal Regulation

See “System Agreement”, “Independent Coordinator of Transmission”, “Notice to SERC Reliability Corporation regarding Reliability Standards”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.

Nuclear Matters

Entergy Arkansas owns and operates, through an affiliate, the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

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Management’s Financial Discussion and Analysis

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials associated with components within the reactor coolant system. The issue is applicable to ANO and is managed in accordance with industry standard practices and guidelines and includes in-service examinations, replacement and mitigation strategy. Several major modifications to the ANO units have been implemented to mitigate the susceptibility of large bore dissimilar metal welds. In addition, a replacement reactor vessel head has been fabricated for ANO 2 and is onsite. Routine inspections of the existing ANO 2 reactor vessel head have identified no significant material degradation issues for that component. These inspections will continue at planned refueling outages. Timing for installation of the new reactor vessel head will be based on the results of future inspection efforts.

Environmental Risks

Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated. See “Uses of Capital” above for a discussion of the potential requirement to install scrubbers and low NOx burners at Entergy Arkansas’s White Bluff coal plant.

Critical Accounting Estimates

The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position or results of operations.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Arkansas records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.

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Entergy Arkansas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost to changes in certain actuarial assumptions (dollars in thousands):

Actuarial Assumption	Change in Assumption	Impact on 2010 Qualified Pension Cost	Impact on Qualified Projected Benefit Obligation
	Increase/(Decrease)

Discount rate	(0.25%)	$2,410	$26,637
Rate of return on plan assets	(0.25%)	$1,489	-
Rate of increase in compensation	0.25%	$1,064	$5,130

The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands):

Actuarial Assumption	Change in Assumption	Impact on 2010 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)

Health care cost trend	0.25%	$1,080	$5,852
Discount rate	(0.25%)	$585	$6,621

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for Entergy Arkansas in 2010 was $31.7 million. Entergy Arkansas anticipates 2011 qualified pension cost to be approximately $33.7 million. Entergy Arkansas’s contributions to the pension trust were $137 million in 2010 and are currently estimated to be approximately $107.1 million in 2011; although the required pension contributions will not be known with more certainty until the January 1, 2011 valuations are completed by April 1, 2011.

Total postretirement health care and life insurance benefit costs for Entergy Arkansas in 2010 were $18.9 million, including $5.3 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas expects 2011 postretirement health care and life insurance benefit costs to approximate $17 million, including $6.3 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas expects to contribute approximately $26.3 million to other postretirement plans in 2011.

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Management’s Financial Discussion and Analysis

Federal Healthcare Legislation

See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Discussion and Analysis for further discussion.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Arkansas, Inc. and Subsidiaries

Little Rock, Arkansas

We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated income statements, consolidated statements of changes in common equity, and consolidated statements of cash flows (pages 264 through 268 and applicable items in pages 49 through 184) for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. and Subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 25, 2011

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Item 11. Executive Compensation

ENTERGY CORPORATION

Information concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings "Compensation Discussion and Analysis," "Executive Compensation Tables," "Nominees for the Board of Directors," and "Non-Employee Director Compensation," all of which information is incorporated herein by reference.

ENTERGY ARKANSAS, ENTERGY GULF STATES LOUISIANA, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS AND ENTERGY TEXAS

COMPENSATION DISCUSSION AND ANALYSIS

Introduction

In this section, the salaries and other compensation elements paid in 2010 to the Chief Executive Officers ("CEOs"), the Principal Financial Officer ("PFO"), the three other most highly compensated executive officers other than the CEO and PFO (collectively, the "Named Executive Officers") of each of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas (the "Subsidiaries") are discussed and analyzed. Entergy believes the executive pay programs described herein and in the accompanying tables have played a material role in its ability to drive strong financial results and to attract and retain a highly experienced and successful management team. The purpose of this section is to provide investors with material information necessary to understand the compensation policies for the Named Executive Officers. This section should be read in combination with the more detailed compensation tables and other data presented elsewhere in this report. For information regarding the compensation of the named executive officers of Entergy Corporation, see the Proxy Statement of Entergy Corporation.

The Named Executive Officers are identified in the Summary Compensation Table immediately following this Compensation Discussion and Analysis. Mr. Leonard, Mr. Denault and Mr. Smith also serve as executive officers of Entergy Corporation. Mr. Leonard, Mr. Denault and Mr. Smith do not receive additional compensation for serving as Named Executive Officers of the Subsidiaries. For more information about the officers of the Subsidiaries, see Part III, Item 10 of this report.

Overview of 2010 Performance and Compensation

2010 Performance and Significant Achievements. Entergy’s businesses delivered strong financial and operational performance in 2010, achieving record operational earnings per share for the sixth year in a row and record cash flow from operations. Entergy’s operational earnings per share increased by 6.4% from 2009 and its consolidated cash flow from operations increased by 33.9%. Entergy believes the efforts in 2010 also have positioned Entergy and the Subsidiaries for future success, as reflected in the following significant achievements and recognitions:

·	Achieved record operational earnings per share and operating cash flow;

·	Increased dividend nearly 11%, while completing $750 million share repurchase program;

·	Implemented major leadership reorganization;

·	Settled successfully Entergy Texas and Entergy Arkansas rate cases;

·	Completed successfully Entergy Arkansas, Entergy Gulf States and Entergy Louisiana storm cost securitizations;

·	Modified successfully Entergy Mississippi’s formula rate plan and successfully settled Entergy Louisiana formula rate plan;

·	Selected five proposals from 2009 Summer Long Term Request for Proposals (one subsequently withdrawn), with definitive agreements targeted for 2011;

·	Obtained approval from the Federal Energy Regulatory Commission for acquisition of Acadia Unit 2 power plant;

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·	Achieved on-line record runs at 5 of 7 Entergy Wholesale Commodity Business nuclear plants;

·	Improved key customer service metrics, including call center responsiveness, low levels of complaints and low levels of outage frequency;

·	Included on the Dow Jones Sustainability World Index for the ninth consecutive year, the only U.S. utility to be so honored;

·	Received the 12th EEI Emergency Assistance Recovery Award, the only company to win emergency response awards every year since first presented in 1998; and

·	Received multiple awards and recognition for community relations, corporate citizenship, climate protection and customer service.

Despite these strong financial and operational results, Entergy’s total shareholder return in 2010 substantially lagged its peers, placing Entergy in the fourth quartile of the Philadelphia Utility Index for 2010 and in the third quartile for the three year period ending December 31, 2010. This is in contrast to Entergy’s total shareholder return measured over the past ten years, which has been in the top quartile of the Philadelphia Utility Index.

2010 Compensation. Due in large part to the effects on Entergy’s business and market salaries of the recent economic downturn, none of the Named Executive Officers received a base salary merit increase in 2010. However, the incentive compensation paid to the Named Executive Officers for 2010 performance reflected both Entergy’s strong financial and operational performance in 2010 and Entergy’s poor 2010 total shareholder return in relation to its peers. The payouts under the annual incentive plan properly rewarded the executive officers for substantially exceeding financial performance objectives in 2010 that were deemed to be important to Entergy and its stakeholders and position Entergy and the Subsidiaries for long term success. The Long-Term Performance Plan, on the other hand, paid out at a substantially lower level than in prior years and substantially below target as a result of Entergy’s poor total shareholder return in relation to its peers. These payouts reflect the pay-for-performance philosophy that underlies Entergy’s incentive compensation programs.

Annual Incentive Compensation Paid for 2010 Financial Performance. The annual incentive program is tied to Entergy’s financial performance through the Entergy Achievement Multiplier (the performance metric used to determine awards under the Annual Incentive Plan), which is determined based on Entergy’s success in achieving its consolidated operational earnings per share and operating cash flow goals. Entergy exceeded its operational earnings per share goal of $6.80 in fiscal 2010 by $0.30 per share, and Entergy exceeded its operating cash flow goal of $3.04 billion by $0.94 billion. This resulted in an Entergy Achievement Multiplier of 172%, with Entergy’s Chief Executive Officer receiving an award equal to 206% of his base salary and the other Named Executive Officers each receiving awards equal to a range of 70% to 120% of their base salaries.

Long-Term Incentive Compensation Paid for 2008-2010 Financial Performance. Under the Long-Term Performance Plan, Entergy measures performance over a three year period by assessing Entergy's total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index, with payouts under the plan tied directly to Entergy’s performance in relation to the other companies in the index over the three year performance period. Relative total shareholder return is used as the measure of performance under this plan because it encourages Entergy’s executives to deliver superior shareholder value in relation to Entergy’s peers. For the 2008 – 2010 performance cycle, Entergy’s total shareholder return in relation to the other companies in the Philadelphia Utility Index resulted in a minimum payout of 10% of target for the performance units granted in 2008.

2010 Changes to Executive Compensation. In 2010, with the assistance of the Personnel Committee’s independent executive compensation consultant, the Personnel Committee completed a review of Entergy’s overall approach to its executive compensation programs, which it undertakes annually to ensure that the programs continue to be in line with best practices of other companies in the industry as well as other Fortune 500 companies. As a result of that review, the Personnel Committee approved a number of changes to the executive compensation programs that are intended to enhance the alignment of the executive compensation programs with best practices at companies in the Philadelphia Utility Index as well as other Fortune 500 companies in general. These changes include:

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·	Elimination of “gross up” payments with respect to excise taxes due on the payment of severance benefits to the named executive officers in the case of a change in control. See “Retention Agreements and Other Compensation Arrangements”.

·	Reduction of the maximum payout under the Long-Term Incentive Plan from 250% to 200% of target beginning with the 2011-2013 performance cycle, combined with an increase in the minimum payout from 10% to 25% of target.

·	Modification of the components of long-term compensation to increase the portion of long-term compensation that will be derived from performance units from 50% to 60% and decrease the portion that will be derived from restricted stock and stock options to 40%.

·	Addition of awards of restricted stock to the executive officers, beginning in 2011, as a component of long-term compensation.

·	Elimination of club dues as a perquisite for the members of the Office of Chief Executive and the elimination of gross-up payments on perquisites.

·	Discontinuation of financial counseling as a perquisite for all executive officers with the value of this discontinued perquisite not being replaced in the executive’s compensation.

·	Adoption of a “double trigger” (requiring both a change in control and an involuntary job loss or substantial diminution of duties) for the acceleration of awards under the 2007 Equity Ownership and Long-Term Cash Incentive Plan.

·	Adoption of a “clawback” policy providing for the recoupment of incentive compensation under appropriate circumstances. See “Executive Compensation Governance”.

·	Adoption of a policy prohibiting hedging transactions in Entergy’s common stock by any officer, director or employee. See “Executive Compensation Governance”.

In January 2011, Entergy’s Board also adopted a policy that prohibits Entergy or its affiliates from engaging the independent consultant that provides executive and director compensation services to the Personnel and Corporate Governance Committees or its affiliates to provide other services to Entergy with an aggregate value in excess of $120,000 in any fiscal year.

Objectives of the Executive Compensation Program

·	The greatest part of the compensation of the Named Executive Officers should be in the form of "at risk" performance-based compensation in order to focus the executives on the achievement of superior results.

The compensation programs are designed to ensure that a significant percentage of the total compensation of the Named Executive Officers is contingent on achievement of performance goals that drive total shareholder return and result in increases in Entergy Corporation's common stock price. For example, each of the annual cash incentive and long-term performance unit programs is designed to pay out only if Entergy achieves pre-established performance goals. If minimum established performance goals are not achieved, no payouts are made under the incentive programs. Assuming achievement of these performance goals at target level, approximately 80% of the annual target total compensation (excluding non-qualified supplemental retirement income) of Entergy Corporation's Chief Executive Officer is at risk because it is performance-based compensation and the remaining 20% is represented by base salary. For Mr. Denault and Mr. Smith, assuming achievement of performance goals at the target levels, approximately 65% of the annual target total compensation (excluding non-qualified supplemental retirement income) is at risk because it is performance-based compensation and the remaining 35% is represented by base salary. For substantially all of the other Named Executive Officers, assuming achievement of performance goals at the target levels, at least 50% of the annual target total compensation (excluding non-qualified supplemental retirement income) is at risk because it is performance-based compensation and the remaining 50% is represented by base salary. Entergy Corporation's Chief Executive Officer's total compensation is at greater risk than the other Named Executive Officers, reflecting both market practice and acknowledging the leadership role of the Chief Executive Officer in setting company policy and strategies.

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·	A substantial portion of the Named Executive Officers' compensation should be delivered in the form of equity awards.

To align the economic interests of the Named Executive Officers with the shareholders of Entergy Corporation, Entergy believes a substantial portion of its total compensation should be in the form of equity-based awards. Historically, awards were granted in the form of stock options with a three-year vesting schedule and performance units with a three-year performance cycle. Beginning in 2011, awards will be granted in the form of restricted stock, stock options and performance units. Stock options and restricted stock generally will be subject only to time-based vesting. Performance units pay out only if Entergy Corporation achieves specified performance targets with the amount of payout contingent on the level of performance achieved. These awards focus and reward executive officers on building shareholder value.

·	The compensation programs of Entergy Corporation and the Subsidiaries should enable the companies to attract, retain and motivate executive talent by offering competitive compensation packages.

It is in the shareholders' best interests that Entergy Corporation and the Subsidiaries attract and retain talented executives by offering compensation packages that are competitive. Entergy Corporation's Personnel Committee has sought to develop compensation programs that deliver total target compensation in aggregate at approximately the 50th percentile of the market.

The Starting Point

To develop a competitive compensation program, the Personnel Committee annually reviews base salary and other compensation data from two sources:

Survey Data: The Committee uses published and private compensation survey data to develop marketplace compensation levels for executive officers. The data, which is compiled by the Committee's independent compensation consultant, compares the current compensation levels received by each of the executive officers against the compensation levels received by executives holding similar positions at companies with corporate revenues consistent with the revenues of Entergy Corporation. For non-industry specific positions such as a chief financial officer, the Committee reviews general industry data. For management positions that are industry-specific such as Group President, Utility Operations, the Committee reviews data from energy services companies. The survey data reviewed by the Committee covers approximately 800 public and private companies in general industry and approximately 100 public and private companies in the energy services sector. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identity of the companies comprising the survey data is not disclosed to, or considered by, the Committee in its decision-making process and, thus, is not considered material by the Committee.

The Committee uses the survey data to develop compensation programs that deliver total target compensation at approximately the 50th percentile of the surveyed companies. This survey data is used as the primary data for purposes of determining target compensation. For this purpose, the Committee reviews the results of the survey data (organized in tabular format) comparing each of the Named Executive Officer's compensation relative to the 25th, 50th (or median) and 75th percentile of the surveyed companies. The Committee considers its objectives to have been met if Entergy Corporation's Chief Executive Officer, the executive officers who constitute what is referred to as the Office of the Chief Executive, considered as a group (9) officers have a target compensation package that falls within the range of 90 - 110 percent of the 50th percentile of the companies in the survey data. In 2010, in the aggregate the target compensation of all of the Named Executive Officers fell within this range. Actual compensation received by an individual officer may be above or below the 50th percentile based on an individual officer's skills, performance and responsibilities, Entergy Corporation performance and internal equity.

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Proxy Analysis: Although the survey data described above is the primary data source used in determining compensation, the Committee reviews data derived from proxy statements as an additional point of analysis. The proxy data is used to compare the compensation levels of the named executive officers against the compensation levels of the corresponding top five highest paid executive officers from 18 of the companies in the Philadelphia Utilities Index. The analysis is used by the Committee to evaluate the reasonableness of the compensation program. The proxy market data compare Entergy executive officers to other proxy officers based on pay rank without regard to roles and responsibilities. These companies are:

· AES Corporation	· Exelon Corporation
· Ameren Corporation	· FirstEnergy Corporation
· American Electric Power Co. Inc.	· NextEra Energy
· CenterPoint Energy Inc.	· Northeast Utilities
· Consolidated Edison Inc.	· PG&E Corporation
· Dominion Resources Inc.	· Progress Energy, Inc.
· DTE Energy Company	· Public Service Enterprise Group, Inc.
· Duke Energy Corporation	· Southern Company
· Edison International	· Xcel Energy

Elements of the Compensation Program

The major components of the executive compensation program are presented below:

Entergy’s executive compensation package consists of a combination of short-term and long-term compensation elements. For 2010, short-term compensation included base pay and annual cash bonus awards and long-term compensation included stock options and performance units. All of the incentive plans are linked to Entergy’s financial and stock performance or its total shareholder return in relation to its peers. The executive compensation program is approved by Entergy’s Personnel Committee, which consists entirely of independent board members.

The executive compensation programs reflect a balanced compensation approach to incentivizing and rewarding performance by combining a market-based base salary with reasonable annual and long-term incentive compensation programs. These incentive compensation programs are designed to reward the executive officers if they attain specified annual and long-term goals while taking an appropriate level of risk.

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The following table summarizes the principal factors that are taken into account in deciding the amount of each compensation element paid or awarded to executives:

Key Compensation Components (where reported in summary compensation table)	Factors
Base Salary (salary, column c)	-Entergy Corporation, business unit and individual performance -Market data -Internal pay equity -The Committee's assessment of other elements of compensation based upon Entergy’s Chief Executive Officer’s recommendations for the Named Executive Officers other than himself
Non-Equity Incentive Plan Compensation (Cash Bonus) (non-equity plan compensation, column g)	-Compensation practices at the peer group companies and the general market for companies Entergy Corporation’s size -Desire to ensure that a substantial portion of total compensation is performance-based -The Committee's assessment of other elements of compensation based upon Entergy’s Chief Executive Officer’s recommendations for the Named Executive Officers other than himself -Entergy Corporation and individual performance
Performance Units (stock awards, column e)	-Compensation practices at the peer group companies and in broader group of utility companies -Target long-term compensation values in the market for similar jobs -The desire to ensure that a substantial portion of total compensation is performance-based -The Committee's assessment of other elements of compensation based upon Entergy’s Chief Executive Officer’s recommendations for the Named Executive Officers other than himself
Stock Options (options, column f)	-Individual performance -Prevailing market practice -Targeted long-term value created by the use of stock options -Potential dilutive effect of stock option grants -The Committee's assessment of other elements of compensation based upon Entergy’s Chief Executive Officer’s recommendations for the Named Executive Officers other than himself

Compensation decisions for each executive officer are made after taking into account all elements of the officer’s compensation. In making compensation decisions, Entergy applies the same compensation policies to all of the executive officers; however, the application of these policies results in different compensation amounts to individual executive officers because of: (i) differences in roles and responsibilities; (ii) differences in market-based compensation levels for specific officer positions; (iii) the assessment of individual performance; (iv) internal equity; and (v) variations in business unit performance.

Short-Term Compensation

·	Base Salary

Base salary is a component of each Named Executive Officer's compensation package because the Committee believes it is appropriate that some portion of the compensation that is provided to these officers is stable. Also, base salary remains the most common form of payment throughout all industries. Its use ensures a competitive compensation package for the Named Executive Officers.

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The Committee (in the case of Mr. Leonard, Mr. Denault and Mr. Smith) or certain senior Entergy officers (in the case of the other Named Executive Officers) determine the base salaries for these Named Executive Officers, including whether to grant annual merit increases in base salary based on the following factors:

·	Entergy Corporation, business unit and individual performance during the prior year;

·	Market data;

·	Internal pay equity; and

·	The Committee's assessment of other elements of compensation provided to the Named Executive Officers; and

·	Entergy’s Chief Executive Officer’s recommendations for the Named Executive Officers other than himself.

The corporate and business unit goals and objectives vary by individual officers and include, among other things, corporate and business unit financial performance, capital expenditures, cost containment, safety, reliability, customer service, business development and regulatory matters.

The use of "internal pay equity" in setting merit increases assists the Committee in determining whether a change in an executive officer's role and responsibilities relative to other executive officers requires an adjustment in the officer's salary. The Committee has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.

In January 2010, in light of the continued uncertainty in economic conditions and the projected slow growth in executive officer salaries in 2010 based on the review of general industry surveys prepared by various human resource consulting firms, the Personnel Committee decided not to increase base salaries from the levels established in 2009 for the executive officers who constitute the Office of the Chief Executive.

In addition, for the same reasons listed above, the 2010 base salaries for Mr. Bunting, Mr. Domino, Mr. Fisackerly, and Mr. McDonald were not increased.

In June 2010, Ms. Conley was promoted from President, Entergy Louisiana to Executive Vice President, Human Resources and Administration. At the same time Mr. West was promoted from President, Entergy New Orleans to Executive Vice President, Chief Administrative Officer. Ms. Conley’s base salary was increased from $407,680 to $425,000, and Mr. West’s base salary was increased from $315,000 to $550,000 to reflect the increased responsibilities of their new positions and comparative market data for officers in similar positions.

Also, in June 2010, Mr. Mohl was promoted to President, Entergy Louisiana and Mr. Rice was promoted to President, Entergy New Orleans. Mr. Mohl’s base salary was increased from $269,088 to $325,000 and Mr. Rice’s base salary was increased from $160,000 to $240,000 to reflect their new positions and responsibilities.

The 2010 base salaries for the Named Executive Officers were:

Named Executive Officer	2010 Base Salary
J. Wayne Leonard	$1,291,500
Leo P. Denault	$630,000
Richard J. Smith	$645,000
Theodore H. Bunting, Jr.	$350,448
E. Renae Conley	$425,000
Joseph F. Domino	$317,754
Haley R. Fisackerly	$275,000
Hugh T. McDonald	$322,132
William M. Mohl	$325,000
Charles L. Rice, Jr.	$240,000
Roderick K. West	$550,000

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Mr. Leonard’s salary is larger than the other Named Executive Officers because of his leadership role in setting company policy and strategic planning and reflects market practice for salaries for chief executive officers.

·	Non-Equity Incentive Plan (Cash Bonus)

Performance-based incentives are included in the Named Executive Officers' compensation packages because Entergy believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall goals and strategic direction that the Entergy Board has set for Entergy Corporation and the Subsidiaries. Annual incentive plans are commonly used by companies in a variety of industry sectors to compensate their executive officers for achieving financial and operational goals.

The Named Executive Officers participate in a performance-based cash bonus plan known as the Executive Annual Incentive Plan or Executive Incentive Plan. Under the plan, Entergy uses a performance metric known as the Entergy Achievement Multiplier to determine the percentage of target annual plan awards that will be paid each year to each Named Executive Officer. Each year the Personnel Committee reviews the performance measures used to determine the Entergy Achievement Multiplier. In December 2009, the Personnel Committee decided to retain the performance measures used in 2009. Accordingly, the 2010 performance measures used to determine the Entergy Achievement Multiplier were consolidated operational earnings per share and operating cash flow, with each measure weighted equally. The Committee selected these performance measures because:

·	earnings per share and operating cash flow have both a correlative and causal relationship to shareholder value over time;

·	earnings per share and operating cash flow targets are aligned with externally-communicated goals; and

·	earnings per share and operating cash flow results are readily available in earning releases and SEC filings.

In addition, these measures are used by a number of other companies, including the companies in the Philadelphia Utility Index, as components of their incentive programs. For example, approximately 72 percent of the industry peer group companies use earnings per share as an incentive measure.

The Committee sets minimum and maximum achievement levels under the Executive Incentive Plan. Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight line interpolation. If Entergy does not achieve its minimum achievement levels, no payout occurs under the Executive Incentive Plan. In general, the Committee seeks to establish target achievement levels such that the relative difficulty of achieving the target level is consistent from year to year. Over the past five years ending with 2010, the average Entergy Achievement Multiplier was 148% of target.

In December 2009, the Committee set the 2010 target awards for incentives to be paid in 2011 under the Executive Incentive Plan. As a percentage of base salary, the target awards for certain of Entergy named executive officers were set as follows: J. Wayne Leonard, CEO of Entergy Corporation (120%); Leo P. Denault, Executive Vice President and Chief Financial Officer (70%); and Richard J. Smith, President Entergy Wholesale Commodity Business (70%). The Committee based its decision on the target awards for Mr. Denault and Mr. Smith on the recommendation of Entergy’s Chief Executive Officer.

In setting these target awards, the Personnel Committee considered several factors, including:

·	Analysis provided by the Committee's independent compensation consultant as to compensation practices at the industry peer group companies and the general market for companies the size of Entergy Corporation;

·	Competitiveness of the compensation plans and Entergy’s ability to attract and retain top executive talent;

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·	The individual performance of each Entergy named executive officer (other than the Chief Executive Officer of Entergy Corporation) as evaluated by the Chief Executive Officer of Entergy Corporation;

·	Target bonus levels in the market for comparable positions;

·	The desire to ensure that a substantial portion of total compensation is performance-based;

·	The relative importance of the short-term performance goals established pursuant to the Executive Incentive Plan;

·	The Committee's assessment of other elements of compensation provided to the Named Executive Officers; and

·	Entergy’s Chief Executive Officer’s recommendations for the Named Executive Officers other than himself.

The target awards for the other Named Executive Officers were set as follows: E. Renae Conley, former CEO - Entergy Gulf States Louisiana and CEO - Entergy Louisiana (60%); Joseph F. Domino, CEO - Entergy Texas (50%); Hugh T. McDonald, CEO - Entergy Arkansas (50%); Roderick K. West, former CEO - Entergy New Orleans (70%); Haley Fisackerly, CEO - Entergy Mississippi (40%); William M. Mohl (60%), CEO - Entergy Gulf States and Entergy Louisiana; Charles L. Rice, Jr. (40%), CEO - Entergy New Orleans and Theodore H. Bunting, Jr. - Principal Accounting Officer - the Subsidiaries (60%).

The target awards for the Named Executive Officers (other than Entergy named executive officers) were set by their respective supervisors (subject to ultimate approval of Entergy’s Chief Executive Officer) who allocated a potential incentive pool established by the Personnel Committee among various of their direct and indirect reports. In setting the target awards, the supervisor took into account considerations similar to those used by the Personnel Committee in setting the target awards for Entergy’s Named Executive Officers.

The Committee established a higher target percentage for Mr. Leonard compared to the other Named Executive Officers to reflect the following factors:

Mr. Leonard's leadership and contributions to Entergy Corporation's success as measured by, among other things, the overall performance of Entergy Corporation, which, as measured by total shareholder return, has exceeded all but one of the companies in the Philadelphia Utility Index over his twelve-year tenure as Chief Executive Officer.

·	Market practices that compensate chief executive officers at greater potential compensation levels with more "pay at risk" than other executive officers.

The Personnel Committee's assessment of Mr. Leonard's strong performance based on the Board's annual performance evaluation, in which the Board reviews and assesses Mr. Leonard's performance based on: leadership, strategic planning, financial results, succession planning, communications with all of Entergy’s stakeholders, external relations with the communities and industries in which Entergy Corporation operates and his relationship with the Board.

Target awards are set based on an executive officer’s current position and executive management level within the Entergy organization. Executive management levels at Entergy range from Level 1 thorough Level 4. Mr. Denault, Mr. Smith and Mr. West hold positions in Level 2 whereas Mr. Bunting, Ms. Conley and Mr. Mohl hold positions in Level 3 and Mr. Domino, Mr. Fisackerly, Mr. McDonald and Mr. Rice hold positions in Level 4. Accordingly, their respective incentive targets differ one from another based on the external market data developed by the Committee’s independent compensation consultant and the other factors noted above.

In December 2009, the Committee determined the Executive Incentive Plan targets to be used for purposes of establishing annual bonuses for 2010. The Committee’s determination of the target levels was made after full Board review of management’s 2010 financial plan for Entergy Corporation, upon recommendation of the Finance Committee, and after the Committee’s determination that the established targets aligned with Entergy Corporation’s anticipated 2010 financial performance as reflected in the financial plan. The targets established to measure management performance against as reported results, excluding the impact of the activities associated with the previously planned separation of the non-utility nuclear business (the “Spin Transaction”) were:

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	Minimum	Target	Maximum
Earnings Per Share ($)	$6.12	$6.80	$7.48
Operating Cash Flow ($ in Billions)	$2.68	$3.04	$3.40

In January 2011, after reviewing earnings per share and operating cash flow results against the performance objectives in the above table, the Committee determined that Entergy Corporation had exceeded the operational EPS target of $6.80 by $0.40 in fiscal 2010 and had exceeded the operating cash flow goal of $3.04 by $0.94 billion. In accordance with the terms of the Executive Incentive Plan, in January 2011, the Personnel Committee certified the 2010 Entergy Achievement Multiplier at 172% of target.

Under the terms of the Management Effectiveness Program, the Entergy Achievement Multiplier is automatically increased by 25 percent for the members of the Office of the Chief Executive if the pre-established underlying performance goals established by the Personnel Committee are satisfied at the end of the performance period, subject to the Personnel Committee's discretion to adjust the automatic multiplier downward or eliminate it altogether. In accordance with Section 162(m) of the Internal Revenue Code, the multiplier which Entergy refers to as the Management Effectiveness Factor is intended to provide the Committee, through the exercise of negative discretion, a mechanism to take into consideration specific achievement factors relating to the overall performance of Entergy Corporation. In January 2011, the Committee exercised its negative discretion to eliminate the Management Effectiveness Factor with respect to the 2010 incentive awards, reflecting the Personnel Committee's determination that the Entergy Achievement Multiplier, in and of itself without the Management Effectiveness Factor, was consistent with the performance levels achieved by management.

The annual incentive awards for the Named Executive Officers (other than Mr. Leonard, Mr. Denault and Mr. Smith) are awarded from an incentive pool approved by the Committee. From this pool, each named executive officer’s supervisor determines the annual incentive payment based on the Entergy Achievement Multiplier. The supervisor has the discretion to increase or decrease the multiple used to determine an incentive award based on individual and business unit performance. The incentive awards are subject to the ultimate approval of Entergy’s Chief Executive Officer.

The following table shows the Executive Incentive Plan payments as a percentage of base salary for 2010 based on an Entergy Achievement Multiplier of 172% as well as the incentive awards for each Named Executive Officer:

Named Executive Officer	Target	Percentage Base Salary	2010 Annual Incentive Award
J. Wayne Leonard	120%	206%	$2,665,656
Leo P. Denault	70%	120%	$758,520
Richard J. Smith	70%	120%	$776,580
Theodore H. Bunting, Jr.	60%	150%	$525,000
E. Renae Conley	60%	103%	$438,600
Joseph F. Domino	50%	100%	$317,754
Haley R. Fisackerly	40%	70%	$192,500
Hugh T. McDonald	50%	92%	$297,972
William M. Mohl	60%	117%	$380,250
Charles L. Rice, Jr.	40%	80%	$192,000
Roderick K. West	70%	120%	$662,200

Long-Term Compensation

Entergy’s goal for long-term incentive compensation is to focus and reward executive officers for building shareholder value and to increase the executive officers’ ownership in Entergy Corporation common stock. In the long-term incentive programs, Entergy has historically used a mix of performance units and stock options. Performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock appreciation and dividend payments relative to the companies in the Philadelphia Utility Index. Stock options provide a direct incentive for increasing the price of Entergy Corporation common stock. In addition, restricted stock units have occasionally been awarded for retention purposes or to offset forfeited compensation in order to attract officers and managers from other companies.

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Beginning in 2011, the long-term incentive program will include awards of restricted stock, in addition to grants of performance units and stock options. For 2010, the target value of long-term incentive compensation granted to an executive was divided equally between the value determined on the date of grant of the performance units and stock options granted under the program. Beginning in 2011, the target value of long-term incentive compensation will be allocated 60% to performance units and 40% to a combination, equally divided, of stock options and restricted stock, all based on their grant date values.

Each of the performance units and stock options granted to the Named Executive Officers in 2010 were awarded under the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation, which is referred to as the 2007 Equity Ownership Plan.

·	Performance Unit Program

Entergy issues performance unit awards to the Named Executive Officers under its Performance Unit Program. Each performance unit equals the cash value of one share of Entergy Corporation common stock at the end of the three-year performance cycle. Each unit also earns the cash equivalent of the dividends paid during the performance cycle. Dividends accrued during the performance cycle are paid out only to the extent the performance measures are achieved and a payout under the program for that cycle occurs. The Performance Unit Program is structured to reward Named Executive Officers only if performance goals set by the Personnel Committee are met. The Personnel Committee has no discretion to make awards if minimum performance goals are not achieved.

The Performance Unit Program provides a minimum, target and maximum achievement level. Performance is measured by assessing Entergy Corporation's total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. The Personnel Committee chose total shareholder return as a measure of performance because it assesses Entergy Corporation's creation of shareholder value relative to other electric utilities over the performance cycle. It also takes into account dividends paid by the companies in this Index and normalizes events that affect the industry as a whole. Minimum, target and maximum performance levels are determined by reference to the percentile ranking of Entergy Corporation's total shareholder return against the total shareholder return of the companies in the Philadelphia Utility Index. At any given time, a participant in the Performance Unit Program is participating in three performance cycles. Currently participants are participating in the 2009-2011, the 2010-2012 and the 2011-2013 cycles.

The 2010-2012 Performance Grant. For the 2010-2012 performance cycle, the Personnel Committee identified the Philadelphia Utility Index as the industry peer group for total shareholder return performance because the companies represented in this index more closely approximate us in terms of size and scale.

Subject to achievement of the Performance Unit Program performance levels, the Personnel Committee established target amounts of 22,300 performance units for Mr. Leonard; and 5,300 performance units for each of Mr. Denault and Mr. Smith for the 2010-2012 performance cycle. The target amounts for the other Named Executive Officers are as follows: 4,583 performance units for Mr. West, 2,220 performance units for Ms. Conley and Mr. Bunting; 1,000 performance units for each of Mr. Domino, Mr. McDonald and Mr. Fisackerly; 2,000 performance units for Mr. Mohl; and 833 performance units for Mr. Rice. The range of payouts under the program is shown below.

Performance Levels:	Minimum	Target	Maximum
Total Shareholder Return	25th percentile	50th percentile	75th percentile
Payouts	10% of Target	100% of Target	250% of Target

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There is no payout for performance below the 25th percentile. Payouts between minimum and target and target and maximum are calculated using straight line interpolation.

The Personnel Committee sets payout opportunities for the Performance Unit Program at the outset of each performance cycle. In determining payout opportunities, the Committee considers several factors, including:

·	The advice of the Committee's independent compensation consultant regarding compensation practices at the industry peer group companies;

·	Competitiveness of Entergy’s compensation plans and their ability to attract and retain top executive talent;

·	Target long-term compensation values in the market for similar jobs;

·	The desire to ensure, as described above, that a substantial portion of total compensation is performance-based;

·	The relative importance of the long-term performance goals established pursuant to the Performance Unit Program; and

·	The Committee’s assessment of other elements of compensation provided to the Named Executive Officers; and

·	Entergy’s Chief Executive Officer’s recommendation for the Named Executive Officers other than himself.

Payout for the 2008-2010 Performance Cycle. For the 2008-2010 performance cycle, the target amounts established in January 2008 were:

·	16,500 performance units for Mr. Leonard;

·	3,900 performance units for Mr. Denault and Mr. Smith;

·	1,400 performance units for Ms. Conley and Mr. Bunting;

·	1,233 performance units for Mr. West;

·	817 performance units for Mr. Mohl;

·	700 performance units each for Mr. Domino and Mr. McDonald; and

·	583 performance units for Mr. Fisackerly.

Mr. Rice was not a participant in the 2008-2010 performance cycle.

Participants could earn performance units consistent with the range of payouts as described above for the 2010-2012 performance cycle. The Committee established a higher target amount for Mr. Leonard compared to the other Named Executive Officers based on the following factors:

·	Mr. Leonard's leadership and contributions to Entergy Corporation's success as measured by, among other things, the overall performance of Entergy Corporation.

·	Market practices that compensate chief executive officers at greater potential compensation levels with more "pay at risk" than other named executive officers.

In January 2011, the Committee assessed Entergy Corporation's total shareholder return for the 2008-2010 performance cycle and determined the actual number of performance units to be paid to Performance Unit Program participants for the 2008-2010 performance cycle. The Committee compared Entergy’s total shareholder return against the total shareholder return of the companies that are included in the Philadelphia Utility Index. Based on this comparison, the Committee concluded that Entergy’s performance for the 2008-2010 performance cycle, ranked at the bottom of the third quartile, or approximately the 25th percentile. This resulted in a payout at 10% of target, or 10% of the target number of units awarded. Each performance unit was then automatically converted into cash at the rate of $70.83 per unit, the closing price of Entergy Corporation’s common stock on the last trading day of the performance cycle (December 31, 2010), plus dividend equivalents accrued over the three-year performance cycle. See the 2010 Stock Option Exercises and Stock Vested table for the amount paid to each of the Named Executive Officers for the 2008-2010 performance cycle.

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·	Stock Options

The Personnel Committee and, in the case of the Named Executive Officers (other than Mr. Leonard, Mr. Denault and Mr. Smith), Entergy’s Chief Executive Officer and the Named Executive Officer’s supervisor consider several factors in determining the amount of stock options it will grant under Entergy’s 2007 Equity Ownership Plan to the Named Executive Officers, including:

·	Individual performance;

·	Prevailing market practice in stock option grants;

·	The targeted long-term value created by the use of stock options;

·	The number of participants eligible for stock options, and the resulting "burn rate" (i.e., the number of stock options authorized divided by the total number of shares outstanding) to assess the potential dilutive effect; and

·	The Committee's assessment of other elements of compensation provided to the Named Executive Officers based upon Entergy’s Chief Executive Officer’s recommendations for the Named Executive Officers other than himself.

For stock option awards to the Named Executive Officers (other than Mr. Leonard), the Committee's assessment of individual performance of each Named Executive Officer in consultation with Entergy Corporation's Chief Executive Officer, which involves a review of each officer’s performance, role and responsibilities, strengths and developmental opportunities is the most important factor in determining the number of options awarded. The Committee also considers the significant achievements of Entergy for the prior year.

The following table sets forth the number of stock options granted to each Named Executive Officer in 2010. The exercise price for each option was $77.10, which was the closing price of Entergy Corporation common stock on the date of grant.

Named Executive Officer	Stock Options
J. Wayne Leonard	135,000
Leo P. Denault	50,000
Richard J. Smith	40,000
Theodore H. Bunting, Jr.	14,500
E. Renae Conley	12,700
Joseph F. Domino	4,600
Haley R. Fisackerly	9,000
Hugh T. McDonald	4,600
Willliam M. Mohl	9,000
Roderick K. West	7,000

The option grants awarded to the Named Executive Officers (other than Mr. Leonard) ranged in number between 4,600 and 50,000 shares. On the date of grant, Mr. Rice was not eligible to receive stock options. In the case of Mr. Leonard, who received 135,000 stock options, the Committee took special note of his performance as Entergy Corporation's Chief Executive Officer. Among other things, the Committee noted that the total shareholder return of Entergy Corporation measured over the eleven-year period between Mr. Leonard's appointment as Chief Executive Officer of Entergy Corporation in January 1999 and the January 29, 2010 grant date exceeded all of the industry peer group companies as well as all other U.S. investor owned electric utility companies.

For additional information regarding stock options awarded in 2010 to each of the Named Executive Officers, see the 2010 Grants of Plan-Based Awards table.

Under the 2007 Equity Ownership Plan and Entergy’s predecessor equity plans, all stock options must have an exercise price equal to the closing fair market value of Entergy Corporation common stock on the date of grant. In 2008, Entergy Corporation implemented guidelines that require an executive officer to achieve and maintain a level of Entergy Corporation stock ownership equal to a multiple of his or her salary. Until an executive officer achieves the multiple of salary ownership position of Entergy Corporation common stock, the executive officer (including a Named Executive Officer) upon exercising any stock option granted on or after January 1, 2003, must retain at least 75% of the after-tax net profit from such stock option exercise in the form of Entergy Corporation common stock. The equity ownership plans prohibit the repricing of “underwater” stock options without shareholder approval.

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Entergy Corporation has not adopted a formal policy regarding the granting of options at times when it is in possession of material non-public information. However, Entergy Corporation generally grants options to Named Executive Officers only during the month of January in connection with its annual executive compensation decisions. On occasion, it may grant options to newly hired employees or existing employees for retention or other limited purposes.

Benefits, Perquisites, Agreements and Post-Termination Plans

·	Pension Plan, Pension Equalization Plan and System Executive Retirement Plan

The Named Executive Officers are eligible to participate in the Pension Plan, Pension Equalization Plan and System Executive Retirement Plan. The Committee believes that these plans are an important part of the Named Executive Officers' compensation program. These plans are important in the recruitment of top talent in the competitive market, as these types of supplemental plans are typically found in companies of similar size to Entergy. These plans serve a critically important role in the retention of the senior executives, as benefits from these plans generally increase for each year that these executives remain employed by an Entergy system company. The plans thereby encourage the most senior executives to remain employed by Entergy and continue their work on behalf of Entergy’s shareholders.

The Named Executive Officers participate in an Entergy Corporation-sponsored pension plan that covers a broad group of employees. This pension plan is a funded, tax-qualified, noncontributory defined benefit pension plan. Benefits under the pension plan are based upon an employee's years of service with an Entergy system company and the employee's average monthly rate of “Eligible Earnings” (which generally includes the employee’s salary and eligible incentive awards, other than incentive awards paid under the Executive Incentive Plan) for the highest consecutive 60 months during the 120 months preceding termination of employment. Benefits under the tax-qualified plan are payable monthly after separation from an Entergy system company. The amount of annual earnings that may be considered in calculating benefits under the tax-qualified pension plan is limited by federal law.

Benefits under the tax-qualified pension plan in which the Named Executive Officer participates are calculated as an annuity equal to 1.5% of a participant's Eligible Earnings multiplied by years of service. Years of service under the pension plan formula cannot exceed 40. Contributions to the pension plan are made entirely by the employer and are paid into a trust fund from which the benefits of participants will be paid.

Entergy Corporation sponsors a Pension Equalization Plan, which is available to a select group of management and highly compensated employees, including the Named Executive Officers (other than Entergy’s Chief Executive Officer). The Pension Equalization Plan is a non-qualified unfunded supplemental retirement plan that provides for the payment to participants from an Entergy System employer's general assets a single lump sum cash distribution upon separation from service generally equal to the actuarial present value of the difference between the amount that would have been payable as an annuity under the tax-qualified pension plan, but for Internal Revenue Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and the amount actually payable as an annuity under the tax-qualified pension plan. The Pension Equalization Plan also takes into account as “Eligible Earnings” any incentive awards paid under the Executive Incentive Plan.

Entergy Corporation also sponsors a System Executive Retirement Plan, which is available to the Company's approximately 60 officers, including the Named Executive Officers (other than Entergy’s Chief Executive Officer). Participation in the System Executive Retirement Plan requires individual approval by the plan administrator. An employee participating in both the System Executive Retirement Plan and the Pension Equalization Plan is eligible to receive only the greater of the two single-sum benefits computed in accordance with the terms and conditions of each plan.

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Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to participants from an Entergy System employer’s general assets a single-sum cash distribution upon separation from service. The single-sum benefit is generally equal to the actuarial present value of a specified percentage of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant's annual rate of base salary and Executive Incentive Plan award for the 3 highest years during the last 10 years preceding termination of employment), after first being reduced by the value of the participant’s tax-qualified Pension Plan benefit and typically any prior employer pension benefit available to the participant.

While the System Executive Retirement Plan has a replacement schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service.

Years of Service	Executives at Management Level 1	Executives at Management Level 3 and above	Executives at Management Level 4
20 years	55.0%	50.0%	45.0%
30 years	65.0%	60.0%	55.0%

Mr. Leonard's retention agreement (as further discussed below) provides that, in lieu of his participation in the Pension Equalization Plan and the System Executive Retirement Plan, upon the termination of his employment (unless such termination is for Cause, as defined in the agreement), he will be entitled to receive a benefit equal to 60% of his Final Average Compensation (as described in the description of the System Executive Retirement Plan above) calculated as a single life annuity and payable as an actuarial equivalent lump sum. This benefit will be reduced by other benefits to which he is entitled from any Entergy Corporation-sponsored pension plan or prior employer pension plans. The terms of Mr. Leonard's Supplemental Retirement Benefit were negotiated at the time of his employment with Entergy Corporation and were designed to, among other things, offset the loss of benefits resulting from Mr. Leonard's resignation from his prior employer. At the time that Entergy recruited Mr. Leonard, he had accumulated twenty-five years of seniority with his prior employer and had served as an executive officer for that employer for over ten years and in an officer-level capacity for over fifteen years.

The Entergy System company employer of Ms. Conley, Mr. Smith and Mr. Denault has agreed to provide service credit to each of them under either the Pension Equalization Plan or the System Executive Retirement Plan. Entergy System company employers typically offer these service credit benefits as one element of the total compensation package offered to new mid-level or senior executives that are recruited from other companies. By offering these executives "credited service," Entergy Corporation is able to compete more effectively to hire these employees by mitigating the potential loss of their pension benefits resulting from accepting employment within the Entergy system.

See the 2010 Pension Benefits table for additional information regarding the operation of the plans described under this caption.

·	Savings Plan

The Named Executive Officers are eligible to participate in an Entergy Corporation-sponsored Savings Plan that covers a broad group of employees. This is a tax-qualified retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30 percent of a participant's base salary up to certain contribution limits defined by law. In addition, under the Savings Plan, the participant's employer matches an amount equal to seventy cents for each dollar contributed by participating employees, including the Named Executive Officers, on the first six percent of their Earnings (as defined in the Savings Plan) for that pay period. Entergy Corporation

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maintains the Savings Plan for employees of participating Entergy System companies, including the Named Executive Officers, because it wishes to encourage employees to save some percentage of their cash compensation for their eventual retirement. The Savings Plan permits employees to make such savings in a manner that is relatively tax efficient. This type of savings plan is also a critical element in attracting and retaining talent in a competitive market.

·	Executive Deferred Compensation

The Named Executive Officers are eligible to defer up to 100% of their Executive Incentive Plan award into either or both the Entergy-sponsored Executive Deferred Compensation Plan and the equity plan. In addition, they are eligible to defer up to 100% of their base salary into the Executive Deferred Compensation Plan.

Entergy provides these benefits because the Committee believes it is standard market practice to permit officers to defer the cash portion of their compensation. The Committee believes that providing this benefit is important as a retention and recruitment tool as many, if not all, of the companies with which they compete for executive talent provide a similar arrangement to their senior employees.

All deferral amounts represent an unfunded liability of the employer. Amounts deferred into the equity plan are deemed invested in phantom shares of Entergy Corporation common stock. Amounts deferred under the Executive Deferred Compensation Plan are deemed invested in one or more of the available investment options (generally mutual funds) offered under the Savings Plan.

Entergy does not "match" amounts that are deferred by employees pursuant to the Executive Deferred Compensation Plan or equity plan. With the exception of allowing for the deferral of federal and state taxes, no additional benefits are provided to the Named Executive Officer for deferring any of the above payments. Any increase in value of the deferred amounts results solely from the increase in value of the investment options selected (phantom Entergy stock or mutual funds available under the Savings Plan).

Additionally, Mr. Leonard currently has deferred account balances under a frozen Defined Contribution Restoration Plan. These amounts are deemed invested in the options available under this plan.

·	Health & Welfare Benefits

The Named Executive Officers are eligible to participate in various health and welfare benefits available to a broad group of employees. These benefits include medical, dental and vision coverage, life and accidental death & dismemberment insurance and long-term disability insurance. Eligibility, coverage levels, potential employee contributions and other plan design features are the same for the Named Executive Officers as for the broad employee population.

·	Executive Long-Term Disability Program

All executive officers, including the Named Executive Officers, are eligible to participate in the Entergy Corporation-sponsored Executive Long-Term Disability program. Individuals who elect to participate in this plan and become disabled under the terms of the plan are eligible for 65 percent of the difference between their base salary and $275,000 (i.e. the base salary that produces the maximum $15,000 monthly disability payment under the Entergy Corporation's general long-term disability plan).

·	Perquisites

Entergy provides the Named Executive Officers with certain perquisites and other personal benefits as part of providing a competitive executive compensation program and for employee retention. The Personnel Committee reviews all perquisites, including the use of corporate aircraft, on an annual basis. As a result of the 2010 review, beginning in 2011, Entergy will not provide personal financial counseling, club dues for members of the Office of Chief Executive and tax gross up payments on perquisites, except for relocation. The Named Executive Officers did not receive any additional compensation for the lost value of these discontinued perquisites.

In 2010, Entergy offered to the Named Executive Officers limited benefits such as the following: corporate aircraft usage, personal financial counseling, club dues, relocation and housing benefits and annual physical exams (which are mandatory for Entergy’s named executive officers). For security and business reasons, Entergy permits its Chief Executive Officer to use its corporate aircraft at its expense for personal use. The other Named Executive Officers may use corporate aircraft for personal travel subject to the approval of Entergy Corporation's Chief Executive Officer. For additional information regarding perquisites, see the "All Other Compensation" column in the Summary Compensation Table.

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·	Retention Agreements and other Compensation Arrangements

The Committee believes that retention and transitional compensation arrangements are an important part of overall compensation. The Committee believes that these arrangements help to secure the continued employment and dedication of the Named Executive Officers, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Committee believes that these arrangements are important as recruitment and retention devices, as all or nearly all of the companies with which Entergy Corporation and the Subsidiaries compete for executive talent have similar arrangements in place for their senior employees.

To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan under which each of the Named Executive Officers (other than Entergy’s Chief Executive Officer and Chief Financial Officer) is entitled to receive "change in control" payments and benefits if such officer's employment is involuntarily terminated. To allow incentive payments under the Executive Incentive Plan to continue to be considered performance-based under Section 162(m), severance payments under the System Executive Continuity Plan are based on a multiple of the sum of an executive officer’s annual base salary plus his or her average Executive Incentive Plan award at target for the two fiscal years immediately preceding the fiscal year in which the termination of employment occurs. Under no circumstances can this multiple exceed 2.99 the sum of (a) annual base salary plus (b) the higher of: (i) the annual incentive award actually awarded to the executive office under the Executive Incentive Plan for the fiscal year immediately preceding the fiscal year in which the termination of employment occurs or (ii) the average Executive Incentive Plan award for the two fiscal years immediately preceding the fiscal year in which the termination of employment occurs. Entergy Corporation has strived to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. Recognizing that market practices have changed, in December 2010, in connection with its review of the compensation practices and policies, the Personnel Committee modified the System Continuity Plan to eliminate tax gross up payments on any severance benefits received under this plan.

In certain cases, the Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the Committee considers the economic value associated with that agreement in making overall compensation decisions for the affected officer. As mentioned above, Entergy Corporation has voluntarily adopted a policy that any severance arrangements providing benefits in excess of 2.99 times an officer's annual base salary and bonus must be approved by its shareholders.

At present, Entergy Corporation has entered into retention agreements with Mr. Leonard, Entergy’s Chief Executive Officer, and Mr. Denault, Entergy’s Chief Financial Officer. In general, these retention agreements provide for "change in control" payments and other benefits in lieu of those provided under the System Executive Continuity Plan. The retention agreements entered into with Mr. Leonard and Mr. Denault reflect, among other things, the competition for chief executive officer and chief financial officer talent in the market place and the Committee's assessment of the critical role of these officers in executing Entergy Corporation's long-term financial and other strategic objectives. Effective January 1, 2010, Entergy made amendments similar to those made to the System Executive Continuity Plan to Mr. Denault’s and Mr. Leonard’s retention agreements to allow incentive payments under the Executive Incentive Plan to continue to be considered performance based under Section 162(m). Based on market data provided by its independent compensation consultant, the Personnel Committee believes the benefits and payment levels under these retention agreements are consistent with market practices. Again to align with best practices, in December 2010, both Mr. Leonard’s and Mr. Denault’s agreements were amended to eliminate tax gross up payments on any severance benefits they may receive under these agreements.

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In December 2009, Entergy Corporation entered into a retention agreement with Richard J. Smith, President, Entergy Wholesale Commodity Business, in order to retain his services should the Spin Transaction not occur. On April 5, 2010, Entergy Corporation announced that it would not proceed with the Spin Transaction. Under this agreement, Mr. Smith remains employed by an Entergy System Company at a management level and with a salary no less than Mr. Smith’s salary as of December 18, 2009. In addition, the agreement provides that Mr. Smith is entitled to receive a lump sum cash payment equal to 1.5 times his base salary as of the date of separation from Entergy if either he (i) remains continuously employed in such capacity for 24 months after April 5, 2010 (the date of the public announcement that the Spin Transaction will not occur) or (ii) remains continuously employed in such capacity for at least six (6) months after April 5, 2010 and thereafter retires with the consent of Entergy’s Chief Executive Officer prior to reaching such 24 months of service. Entergy entered into this agreement with Mr. Smith in light of Mr. Smith’s leadership role in the preparations for the Spin Transaction and the critical role that Mr. Smith would have in dismantling these preparations if the Spin Transaction did not occur. In determining the type and size of the amount of payment under this agreement, the Personnel Committee consulted with its independent compensation consultant to confirm that the economic value of this arrangement was consistent with market practices.

For additional information regarding the System Executive Continuity Plan and the retention agreements described above, see "Potential Payments upon Termination or Change in Control."

Compensation Program Administration

Executive Compensation Governance

Entergy Corporation periodically reviews the compensation philosophy and makes adjustments that are believed to be in the in best interest of Entergy and its shareholders. Some of the actions taken include the following:

Entergy’s ultimate objective is to deliver long-term value to shareholders as well as other stakeholders such as customers and employees. Entergy continually reviews and adjusts the pay programs so that the primary focus is on long-term success. Executives understand that successful long-term decision making will allow them to be paid their target compensation. Short term decisions that impair the long term value will reduce an executive’s compensation over the long term. To further this objective, in 2011, Entergy increased the portion of long-term compensation that will be derived from performance units from 50% to 60% and decreased the portion that will be derived from other equity awards to 40%. Entergy added restricted stock awards to the long-term compensation program because it believes the use of restricted stock enhances retention, mitigates the burn rate and assists in building ownership of its common stock.

The Entergy Board of Directors adopted the Entergy Corporation Policy Regarding Recoupment of Certain Compensation in December 2010. This policy covers executive officers who are subject to Section 16 of the Exchange Act. Under the policy, the Committee will require reimbursement of incentives paid these executives where:

the payment was predicated upon the achievement of certain financial results with respect to the applicable performance period that were subsequently the subject of a material restatement other than a restatement due to changes in accounting policy or a material miscalculation of a performance award occurs whether or not the financial statements were restated;

·	in the Board of Directors’ view, the elected officer engaged in fraud that caused or partially caused the need for the restatement or caused a material miscalculation of a performance award whether or not the financial statements were restated; and

·	a lower payment would have been made to the elected officer based upon the restated financial results or miscalculation.

The amount the Committee requires to be reimbursed is equal to the excess of the gross incentive payment made over the gross payment that would have been made if the original payment had been determined based on the restated financial results or correct calculation. Further, following a material restatement of its financial statements, Entergy Corporation will seek to recover any compensation received by the Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Section 304 of the Sarbanes-Oxley Act of 2002

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The Committee has formalized the timing and process for reviewing the executive compensation consultant services and fees. Annually, the Committee reviews the relationship with its compensation consultant including services provided, quality of those services and fees associated with services during the fiscal year to ensure executive compensation consultant independence is maintained. To ensure the independence of the Committee’s compensation consultant, in January 2011, Entergy’s Board adopted a policy that any consultant (including its affiliates) retained by the Board of Directors or any Committee of the Board of Directors to provide advice or recommendations on the amount or form of executive and director compensation should not be retained by Entergy Corporation or any of its affiliates to provide other services in an aggregate amount that exceeds $120,000 in any fiscal year.

In 2010, Entergy also adopted an anti-hedging policy which prohibits officers, directors and employees from entering into hedging or monetization transactions involving Entergy Corporation common stock. Prohibited transactions include, without limitation, zero-cost collars, forward sale contracts, purchase or sale of options, puts, calls, straddles or equity swaps or other derivatives that are directly linked to the Entergy’s stock or transactions involving “short-sales” of Entergy’s stock. The Entergy Board adopted this policy to require officers, directors and employees to continue to own Entergy Corporation common stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with Entergy’s other shareholders.

Reviewing the Executive Compensation Programs and Establishing Compensation Levels.

Role of Personnel Committee

The Personnel Committee has overall responsibility for approving the compensation program for the Named Executive Officers and makes all final compensation decisions regarding Entergy’s named executive officers. The Committee works with the executive management to ensure that the compensation policies and practices are consistent with Entergy’s values and support the successful recruitment, development and retention of executive talent so it can achieve the business objectives and optimize the long-term financial returns. The Committee evaluates executive pay each year to ensure that the compensation policies and practices are consistent with Entergy’s philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to Entergy Corporation's named executive officers:

·	developing and implementing compensation policies and programs for the executive officers, including any employment agreement with an executive officer;

·	evaluating the performance of Entergy Corporation's Chairman and Chief Executive Officer; and

·	reporting, at least annually, to the Board on succession planning, including succession planning for Entergy Corporation's Chief Executive Officer.

Certain aspects of the compensation of officers who are not Entergy named executive officers, Mr. Bunting, Ms. Conley, Mr. Domino, Mr. Fisackerly, Mr. McDonald, Mr. Mohl and Mr. Rice are not directly determined by the Personnel Committee. While the Committee does determine the number of performance units to be granted to these Named Executive Officers, the Committee does not determine the actual annual incentive target for these Named Executive Officers. Rather, the Committee establishes an overall available annual incentive pool for these officers and establishes the specific goal targets and ranges, the officers’ respective supervisor determines the actual incentive payment, in each case, subject to the ultimate approval of Entergy’s Chief Executive Officer. Further, Entergy’s Chief Executive Officer and the officer’s supervisor have ultimate responsibility for adjusting the salary of these Named Executive Officers as deemed appropriate. The officer’s supervisor and Entergy’s Chief Executive Officer also determine how many stock option awards are to be allocated to the Named Executive Officers from an available pool established by the Personnel Committee for similarly situated officers, though the Personnel Committee ultimately approves the options granted.

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Role of Chief Executive Officer

The Personnel Committee solicits recommendations from Mr. Leonard, Entergy Corporation's Chief Executive Officer, with respect to compensation decisions for Mr. Denault and Mr. Smith. The Personnel Committee also relies on the recommendations of the senior human resources executives with respect to compensation decisions, policies and practices. Entergy’s Chief Executive Officer’s role is limited to:

·	providing the Committee with an assessment of the performance of Mr. Denault and Mr. Smith; and

·	recommending base salary, annual merit increases, stock option, restricted stock and annual cash incentive plan compensation amounts for these officers.

In addition, the Committee may request that Mr. Leonard provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in structure of bonus programs. Mr. Leonard does not play any role with respect to any matter affecting his own compensation nor does he have any role determining or recommending the amount, or form, of director compensation.

As noted above, under “Role of Personnel Committee,” Mr. Leonard also plays a role in determining the Subsidiary Named Executive Officers’ base salary, their annual incentive target and the number of stock options they receive.

Mr. Leonard may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. However, he is not in attendance at any meeting when the Committee determines and approves the compensation to be paid to the Named Executive Officers. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During 2010, Mr. Leonard attended 6 meetings of the Personnel Committee.

Role of the Compensation Consultant

The Personnel Committee has the sole authority from the Entergy Board of Directors for the appointment, compensation and oversight of its outside compensation consultant. Prior to the engagement of Pay Governance LLC, the Committee’s current independent compensation consultant, in October 2010, the Personnel Committee retained Towers Watson as its independent compensation consultant to assist it in, among other things, evaluating different compensation programs and developing market data to assess the compensation programs. Under the terms of its engagement, Towers Watson reported directly to the Personnel Committee, which had the right to retain or dismiss the consultant without the consent of Entergy’s management. In addition, the consent of the Personnel Committee was required to be obtained before Towers Watson could accept any material engagements recommended by Entergy’s management.

In considering the appointment of Towers Watson, the Personnel Committee took into account that Towers Watson provided from time to time general consulting services to Entergy’s management with respect to non-executive compensation matters. In this connection the Committee reviewed the fees and compensation received by Towers Watson for these services over a historical period. After considering the nature and scope of these engagements and the fee arrangements involved, the Personnel Committee determined that the engagements did not create a conflict of interest. The Committee subsequently reviewed on an ongoing basis the fees and compensation received by Towers Watson for non-executive compensation matters to monitor its independence.

During the first nine months of 2010, the Committee retained the consulting firm of Towers Watson as its consultant to assist the Committee with its responsibilities related to the Entergy Corporation’s compensation programs for its executives. Specifically, the Committee directed Towers Watson to: (i) regularly attend meetings of the Committee, (ii) conduct studies of competitive compensation practices, (iii) identify Entergy’s survey and proxy peer group, (iv) review base salary, annual incentives and long-term incentive compensation opportunities relative to competitive practices, and (v) develop conclusions and recommendations related to the executive compensation plan of Entergy for consideration by the Committee. A senior consultant from Towers Watson generally attended most Personnel Committee meetings. In its role as advisor to the Committee, Towers Watson presented annual reports to the committee on executive and director compensation. In 2010, Entergy incurred in the aggregate fees of $259,286 from Towers Watson for determining or recommending the amount or form of executive and director compensation and $946,326 for others services, $877,331 of which was related to the Spin Transaction.

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Pay Governance LLC was engaged by the Committee as its executive compensation consultant for the remainder of 2010. Pay Governance is not affiliated with Towers Watson. Pay Governance reviewed Entergy’s compensation practices and made recommendations regarding its 2011 executive compensation program. Pay Governance did not provide any other services to Entergy.

Tax and Accounting Considerations

Section 162(m) of the Internal Revenue Code limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to a Chief Executive Officer or any of its other Named Executive Officers (other than the chief financial officer), unless that compensation is "performance-based compensation" within the meaning of Section 162(m). The Personnel Committee considers deductibility under Section 162(m) as it structures the compensation packages that are provided to Entergy’s Named Executive Officers. However, the Personnel Committee and the Board believe that it is in the best interest of Entergy Corporation that the Personnel Committee retains the flexibility and discretion to make compensation awards, whether or not deductible. This flexibility is necessary to foster achievement of performance goals established by the Personnel Committee as well as other corporate goals that the Committee deems important to Entergy Corporation and the Subsidiaries' success, such as encouraging employee retention and rewarding achievement.

Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to Entergy’s Named Executive Officers. However, the Personnel Committee and the Entergy Board of Directors believe that it is in the best interest of Entergy that the Personnel Committee retains the flexibility and discretion to make compensation awards regardless of their financial accounting consequences.

PERSONNEL COMMITTEE REPORT

The "Personnel Committee Report" included in the Entergy Corporation Proxy Statement is incorporated by reference, but will not be deemed to be "filed" in this Annual Report on Form 10-K. None of the Subsidiaries has a compensation committee, or other board committee performing equivalent functions. The board of directors of each of the Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Subsidiaries.

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EXECUTIVE COMPENSATION TABLES

2010 Summary Compensation Table

The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal years ended December 31, 2010, 2009 and 2008. For information on the principal positions held by each of the Named Executive Officers, see Item 10, “Directors and Executive Officers of the Registrants.” The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. None of the Entergy System companies has entered into any employment agreements with any of the Named Executive Officers (other than the retention agreements described in “Potential Payments upon Termination or Change in Control”). For additional information regarding the material terms of the awards reported in the following tables, including a general description of the formula or criteria to be applied in determining the amounts payable, see “Compensation Discussion and Analysis.”

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name and Principal Position	Year	Salary (1)	Bonus (2)	Stock Awards (3)	Option Awards (4)	Non-Equity Incentive Plan Compensation (5)	Change in Pension Value and Non-qualified Deferred Compensation Earnings (6)	All Other Compensation (7)	Total

Theodore H. Bunting, Jr.	2010	$350,448	$ -	$237,864	$194,155	$525,000	$392,300	$22,609	$1,722,376
Acting principal financial	2009	$361,388	$ -	$174,380	$143,280	$335,000	$535,700	$23,065	$1,572,813
officer – Entergy Arkansas,	2008	$336,948	$ -	$201,964	$289,350	$400,023	$225,000	$61,294	$1,514,579
Entergy Gulf States Louisiana,
Entergy Louisiana, Entergy
Mississippi, Entergy New
Orleans, Entergy Texas

E. Renae Conley	2010	$417,006	$ -	$237,864	$170,053	$438,600	$313,100	$62,871	$1,639,494
Former CEO-Entergy Louisiana	2009	$423,360	$15,000	$174,380	$149,250	$307,000	$406,000	$42,899	$1,517,889
and Former CEO-Entergy Gulf	2008	$403,096	$ -	$201,964	$250,770	$415,000	$107,700	$90,525	$1,469,055
States Louisiana

Leo P. Denault	2010	$630,000	$ -	$573,036	$669,500	$758,520	$528,600	$52,276	$3,211,932
Executive Vice President and	2009	$654,231	$ -	$418,512	$537,300	$507,150	$837,200	$60,688	$3,015,081
CFO – Entergy Corp.	2008	$621,231	$ -	$3,114,534	$803,750	$617,400	$250,500	$150,285	$5,557,700

Joseph F. Domino	2010	$317,754	$ -	$108,120	$61,594	$317,754	$224,500	$33,476	$1,063,198
CEO - Entergy Texas	2009	$329,976	$10,000	$78,471	$53,730	$111,373	$322,100	$45,396	$951,046
	2008	$314,610	$ -	$100,982	$112,525	$230,000	$92,800	$62,873	$913,790

Haley R. Fisackerly	2010	$274,999	$ -	$108,120	$120,510	$192,500	$190,000	$39,370	$925,499
CEO – Entergy Mississippi	2009	$274,999	$8,250	$78,471	$45,372	$138,000	$168,300	$35,675	$749,067
	2008	$248,346	$41,000	$84,104	$64,550	$125,700	$143,500	$14,531	$721,731

J. Wayne Leonard	2010	$1,291,500	$ -	$2,411,076	$1,807,650	$2,665,656	$ -	$104,185	$8,280,067
Chairman of the Board and	2009	$1,341,174	$ -	$10,067,775	$1,492,500	$1,782,270	$499,800	$200,040	$15,383,559
CEO - Entergy Corp.	2008	$1,273,523	$ -	$2,380,290	$2,813,125	$2,169,720	$313,200	$759,739	$9,709,597

Hugh T. McDonald	2010	$322,132	$ -	$108,120	$61,594	$297,972	$205,000	$54,990	$1,049,808
CEO-Entergy Arkansas	2009	$324,610	$10,000	$78,471	$53,730	$128,066	$252,500	$67,221	$914,598
	2008	$319,286	$ -	$100,982	$112,525	$160,500	$42,700	$74,830	$810,823

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(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name and Principal Position	Year	Salary (1)	Bonus (2)	Stock Awards (3)	Option Awards (4)	Non-Equity Incentive Plan Compensation (5)	Change in Pension Value and Non-qualified Deferred Compensation Earnings (6)	All Other Compensation (7)	Total

William M. Mohl	2010	$299,193	$ -	$216,240	$120,510	$380,250	$166,718	$148,767	$1,331,678
CEO-Entergy Louisiana and
CEO-Entergy Gulf States
Louisiana

Charles L. Rice, Jr.	2010	$203,879	$9,962	$90,064	$ -	$192,000	$30,944	$18,708	$545,557
CEO-Entergy New Orleans

Richard J. Smith	2010	$645,000	$ -	$573,036	$535,600	$776,580	$607,000	$242,032	$3,379,248
President, Entergy Wholesale	2009	$669,807	$ -	$418,512	$417,900	$519,225	$755,900	$140,779	$2,922,123
Commodity Business	2008	$638,394	$ -	$562,614	$562,625	$632,100	$391,400	$220,708	$3,007,841

Roderick K. West	2010	$441,539	$ -	$495,514	$93,730	$662,200	$207,000	$46,915	$1,946,898
Former CEO-Entergy	2009	$327,115	$15,000	$78,471	$59,700	$158,000	$191,200	$40,883	$870,369
New Orleans	2008	$300,474	$ -	$1,780,832	$128,600	$252,000	$164,200	$54,465	$2,680,571

(1)	The amounts in column (c) represent the actual base salary paid to the Named Executive Officer.
(2)	The amount in column (d) for 2010 for Mr. Rice represents his cash payment received under the Operational Incentive Plan. In 2009, Ms. Conley, Mr. Domino, Mr. Fisackerly, Mr. McDonald and Mr. West received a cash bonus in lieu of an increase in their base salary. In 2008, Mr. Fisackerly received a cash bonus to compensate him for his discontinued participation in the Nuclear Retention Plan.
(3)	The amounts in column (e) represent the aggregate grant date fair value of performance units granted under the Performance Unit Program of the 2007 Equity Ownership Plan calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of performance units is based on the probable outcome of the applicable performance conditions, measured using a Monte Carlo simulation valuation model. The simulation model applies a risk-free interest rate and an expected volatility assumption. The risk-free rate is assumed to equal the yield on a three-year treasury bond on the grant date. Volatility is based on historical volatility for the 36-month period preceding the grant date. If the highest achievement level is attained, the maximum amounts that will be received with respect to these performance units are as follows: Mr. Bunting, $424,050; Ms. Conley, $424,050; Mr. Denault, $1,021,575; Mr. Domino, $192,750; Mr. Fisackerly, $192,750; Mr. Leonard, $4,298,325; Mr. McDonald, $192,750; Mr. Mohl, $385,500; Mr. Rice, $160,599; Mr. Smith, $1,021,575; and Mr. West, $883,412. Amounts shown in this column for 2008 and 2009 vary from amounts shown in prior years due to a change in the method used to value performance units. Amounts presented for those prior years have been recalculated using the valuation method currently used.
(4)	The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2007 Equity Ownership Plan calculated in accordance with FASB ASC Topic 718. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the Financial Statements.
(5)	The amounts in column (g) represent cash payments made under the Executive Incentive Plan.
(6)	The amounts in column (h) include the annual actuarial increase in the present value of the Named Executive Officer’s benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation’s financial statements and includes amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2010 Pension Benefits”). None of the increase is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2010 Non-qualified Deferred Compensation”). For 2010 the aggregate change in the actuarial present value of Mr. Leonard’s pension benefits was a decrease of $539,200.

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(7)

The amounts set forth in column (i) for 2010 include (a) matching contributions by Entergy Corporation to each of the Named Executive Officers; (b) life insurance premiums; (c) tax gross up payments relating to perquisites; (d) dividends paid on stock awards and (e) perquisites and other compensation. The amounts are listed in the following table:

Named Executive Officer	Company Contribution – Savings Plan	Life Insurance Premium	Tax Gross Up Payments	Perquisites and Other Compensation	Total
Theodore H. Bunting, Jr.	$10,830	$3,732	$ -	$8,047	$22,609
Renae E. Conley	$10,526	$1,012	$14,110	$37,223	$62,871
Leo P. Denault	$10,403	$4,002	$10,453	$27,418	$52,276
Joseph F. Domino	$10,830	$5,900	$6,285	$10,461	$33,476
Haley R. Fisackerly	$6,884	$405	$12,529	$19,552	$39,370
J. Wayne Leonard	$10,830	$11,484	$25,739	$56,132	$104,185
Hugh T. McDonald	$7,898	$3,420	$14,517	$29,155	$54,990
William M. Mohl	$10,290	$3,142	$34,546	$100,789	$148,767
Charles L. Rice, Jr.	$8,175	$2,619	$2,421	$5,493	$18,708
Richard J. Smith	$10,830	$3,070	$130,221	$97,911	$242,032
Roderick K. West	$10,290	$978	$7,463	$28,184	$46,915

Perquisites and Other Compensation

The amounts set forth in column (i) include perquisites and other personal benefits that Entergy Corporation provides to the Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. The following perquisites and other compensation were provided by Entergy Corporation in 2010 to the Named Executive Officers:

Named Executive Officer	Financial Counseling	Club Dues	Personal Use of Corporate Aircraft	Relocation	Executive Physicals
Theodore H. Bunting, Jr.			x
E. Renae Conley	x		x	x	x
Leo P. Denault	x		x		x
Joseph F. Domino	x
Haley R. Fisackerly	x	x
J. Wayne Leonard	x		x		x
Hugh T. McDonald	x	x			x
William M. Mohl	x			x
Charles L. Rice, Jr.		x
Richard J. Smith	x		x	x	x
Roderick K West	x	x	x		x

For security and business reasons, Entergy Corporation permits Mr. Leonard to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other Named Executive Officers may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. The aggregate incremental aircraft usage cost associated with Mr. Leonard’s personal use of the corporate aircraft, including the costs associated with travel to outside board meetings, was $30,381 for fiscal year 2010. These amounts are reflected in column (i) and the total above. The incremental cost to Entergy Corporation for use of the corporate aircraft is based on the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications and fees, including flight planning, ground handling and landing permits.

In addition, in accordance with Entergy Corporation’s relocation policies, Entergy Corporation paid to relocate Ms. Conley, Mr. Mohl and Mr. Smith. The cost of their relocations was as follows: $21,301 for Ms. Conley; $90,086 for Mr. Mohl and $71,944 for Mr. Smith. These amounts reflect payments made to the relocation service provider and temporary living expenses.

None of the other individual perquisites items exceeded $25,000 for any of the Named Executive Officers.

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Beginning in 2011, Entergy Corporation will not provide personal financial counseling, club dues for the members of the Office of Chief Executive or tax gross up payments on any perquisites, except for relocation. Entergy Corporation did not replace the value of these discontinued perquisites in the executive’s compensation.

2010 Grants of Plan-Based Awards

The following table summarizes award grants during 2010 to the Named Executive Officers.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)			Estimated Future Payouts under Equity Incentive Plan Awards(2)
(a) Name	(b) Grant Date	(c) Thresh- old ($)	(d) Target ($)	(e) Maximum ($)	(f) Threshold (#)	(g) Target (#)	(h) Maximum (#)	(i) All Other Stock Awards: Number of Shares of Stock or Units (#)	(j) All Other Option Awards: Number of Securities Under- lying Options (#) (3)	(k) Exercise or Base Price of Option Awards ($/Sh)	(l) Grant Date Fair Value of Stock and Option Awards (4)

Theodore H. Bunting, Jr.	1/28/10	-	$210,268	$420,536
	1/28/10				220	2,200	5,500				$237,864
	1/28/10								14,500	$77.10	$194,155

E. Renae Conley	1/28/10	-	$255,000	$510,000
	1/28/10				220	2,200	5,500				$237,864
	1/28/10								12,700	$77.10	$170,053

Leo P. Denault	1/28/10	-	$441,000	$882,000
	1/28/10				530	5,300	13,250				$573,036
	1/28/10								50,000	$77.10	$669,500

Joseph F. Domino	1/28/10	-	$158,877	$317,754
	1/28/10				100	1,000	2,500				$108,120
	1/28/10								4,600	$77.10	$61,594

Haley R. Fisackerly	1/28/10	-	$110,000	$220,000
	1/28/10				100	1,000	2,500				$108,120
	1/28/10								9,000	$77.10	$120,510

J. Wayne Leonard	1/28/10	-	$1,549,800	$3,099,600
	1/28/10				2,230	22,300	55,750				$2,411,076
	1/28/10								135,000	$77.10	$1,807,650

Hugh T. McDonald	1/28/10	-	$161,066	$322,132
	1/28/10				100	1,000	2,500				$108,120
	1/28/10								4,600	$77.10	$61,594

William M. Mohl	1/28/10	-	$195,000	$390,000
	1/28/10				200	2,000	5,000				$216,240
	1/28/10								9,000	$77.10	$120,510

Charles L. Rice, Jr.	1/28/10	-	$96,000	$192,000
	1/28/10				83	833	2,083				$90,064

Richard J. Smith	1/28/10	-	$451,500	$903,000
	1/28/10				530	5,300	13,250				$573,036
	1/28/10								40,000	$77.10	$535,600

Roderick K. West	1/28/10	-	$385,000	$770,000
	1/28/10				458	4,583	11,458				$495,514
	1/28/10								7,000	$77.10	$93,730

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(1)	The amounts in columns (c), (d) and (e) represent minimum, target and maximum payment levels under the Executive Incentive Plan. The actual amounts awarded are reported in column (g) of the Summary Compensation Table.
(2)	The amounts in columns (f), (g) and (h) represent the minimum, target and maximum payment levels under the Performance Unit Program. Performance under the program is measured by Entergy Corporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index. If Entergy Corporation’s total shareholder return is not at least 25% of that for the Philadelphia Utility Index, there is no payout. Subject to achievement of performance targets, each unit will be converted into the cash equivalent of one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2012.)
(3)	The amounts in column (j) represent options to purchase shares of Entergy Corporation’s common stock. The options vest one-third on each of the first through third anniversaries of the grant date. The options have a ten-year term from the date of grant. The options were granted under the 2007 Equity Ownership Plan.
(4)	The amounts included in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions. See Notes 2 and 3 to the Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.

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2010 Outstanding Equity Awards at Fiscal Year-End

The following table summarizes unexercised options, stock that has not vested and equity incentive plan awards for each Named Executive Officer outstanding as of the end of 2010.

	Option Awards					Stock Awards
(a) Name	(b) Number of Securities Underlying Unexercised Options (#) Exercisable	(c) Number of Securities Underlying Unexercised Options (#) Unexercisable	(d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	(e) Option Exercise Price ($)	(f) Option Expiration Date	(g) Number of Shares or Units of Stock That Have Not Vested (#)	(h) Market Value of Shares or Units of Stock That Have Not Vested ($)	(i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	(j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)

Theodore H. Bunting, Jr.	-	14,500(1)		$77.10	1/28/2020
	4,000	8,000(2)		$77.53	1/29/2019
	12,000	6,000(3)		$108.20	1/24/2018
	10,000	-		$91.82	1/25/2017
	5,000	-		$68.89	1/26/2016
	2,200	-		$69.47	1/27/2015
	1,000	-		$58.60	3/02/2014
								220(4)	$15,583
								200(5)	$14,166


E. Renae Conley	-	12,700(1)		$77.10	1/28/2020
	4,166	8,334(2)		$77.53	1/29/2019
	10,400	5,200(3)		$108.20	1/24/2018
	10,000	-		$91.82	1/25/2017
	7,050	-		$68.89	1/26/2016
	7,500	-		$69.47	1/27/2015
	9,200	-		$58.60	3/02/2014
	12,000	-		$44.45	1/30/2013
								220(4)	$15,583
								200(5)	$14,166

Leo P. Denault	-	50,000(1)		$77.10	1/28/2020
	15,000	30,000(2)		$77.53	1/29/2019
	33,333	16,667(3)		$108.20	1/24/2018
	60,000	-		$91.82	1/25/2017
	50,000	-		$68.89	1/26/2016
	35,000	-		$69.47	1/27/2015
	40,000	-		$58.60	3/02/2014
	676	-		$52.40	2/11/2012
	9,800	-		$44.45	1/30/2013
	19,656	-		$41.69	2/11/2012
								530(4)	$37,540
								480(5)	$33,998
						24,000(6)	$1,699,920

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	Option Awards					Stock Awards
(a) Name	(b) Number of Securities Underlying Unexercised Options (#) Exercisable	(c) Number of Securities Underlying Unexercised Options (#) Unexercisable	(d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	(e) Option Exercise Price ($)	(f) Option Expiration Date	(g) Number of Shares or Units of Stock That Have Not Vested (#)	(h) Market Value of Shares or Units of Stock That Have Not Vested ($)	(i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	(j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)

Joseph F. Domino	-	4,600(1)		$77.10	1/28/2020
	1,500	3,000(2)		$77.53	1/29/2019
	4,666	2,334(3)		$108.20	1/24/2018
	12,000	-		$91.82	1/25/2017
	7,500	-		$68.89	1/26/2016
	10,000	-		$69.47	1/27/2015
	10,000	-		$58.60	3/02/2014
	10,500	-		$44.45	1/30/2013
								100(4)	$7,083
								90(5)	$6,375

Haley R. Fisackerly	-	9,000(1)		$77.10	1/28/2020
	1,266	2,534(2)		$77.53	1/29/2019
	3,333	1,667(3)		$108.20	1/24/2018
	2,500	-		$91.82	1/25/2017
	1,000	-		$68.89	1/26/2016
								100(4)	$7,083
								90(5)	$6,375

J. Wayne Leonard	-	135,000(1)		$77.10	1/28/2020
	41,666	83,334(2)		$77.53	1/29/2019
	116,666	58,334(3)		$108.20	1/24/2018
	255,000	-		$91.82	1/25/2017
	210,000	-		$68.89	1/26/2016
	165,200	-		$69.47	1/27/2015
	220,000	-		$58.60	3/02/2014
	195,000	-		$44.45	1/30/2013
	330,600	-		$41.69	2/11/2012
								2,230(4)	$157,951
								2,250(5)	$159,368
						100,000(7)	$7,083,000

Hugh T. McDonald	-	4,600(1)		$77.10	1/28/2020
	1,500	3,000(2)		$77.53	1/29/2019
	4,666	2,334(3)		$108.20	1/24/2018
	12,000	-		$91.82	1/25/2017
	7,500	-		$68.89	1/26/2016
	12,522	-		$73.25	2/11/2012
	10,000	-		$69.47	1/27/2015
	10,000	-		$58.60	3/02/2014
	12,000	-		$44.45	1/30/2013
								100(4)	$7,083
								90(5)	$6,375

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	Option Awards					Stock Awards
(a) Name	(b) Number of Securities Underlying Unexercised Options (#) Exercisable	(c) Number of Securities Underlying Unexercised Options (#) Unexercisable	(d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	(e) Option Exercise Price ($)	(f) Option Expiration Date	(g) Number of Shares or Units of Stock That Have Not Vested (#)	(h) Market Value of Shares or Units of Stock That Have Not Vested ($)	(i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	(j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)

William M. Mohl	-	9,000(1)		$77.10	1/28/2020
	2,500	5,000(2)		$77.53	1/29/2019
	6,200	3,100 (3)		$108.20	1/24/2018
	3,500	-		$91.82	1/25/2017
	5,000	-		$68.89	1/26/2016
	3,000	-		$69.47	1/27/2015
								200(4)	$14,166
								145(5)	$10,270

Charles L. Rice, Jr.								83(4)	$5,879
								45(5)	$3,187

Richard J. Smith	-	40,000(1)		$77.10	1/28/2020
	11,666	23,334(2)		$77.53	1/29/2019
	23,333	11,667(3)		$108.20	1/24/2018
	60,000	-		$91.82	1/25/2017
	50,000	-		$68.89	1/26/2016
	40,000	-		$69.47	1/27/2015
	63,600	-		$58.60	3/02/2014
	50,000	-		$44.45	1/30/2013
	70,000	-		$41.69	2/11/2012
								530(4)	$37,540
								480(5)	$33,998

Roderick K. West	-	7,000(1)		$77.10	1/28/2020
	1,666	3,334(2)		$77.53	1/29/2019
	5,333	2,667(3)		$108.20	1/24/2018
	12,000	-		$91.82	1/25/2017
	1,334	-		$68.89	1/26/2016
	667	-		$69.47	1/27/2015
								458(4)	$32,440
								285(5)	$20,187
						15,000(8)	$1,062,450

(1)	Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/28/2011, 1/28/2012 and 1/28/2013.
(2)	Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/29/2011 and 1/29/2012.
(3)	The remaining unexercisable options vested on 1/24/2011.
(4)	Consists of performance units that will vest on December 31, 2012 only if, and to the extent that, Entergy Corporation attains achievement level as described under “Long-Term Compensation – Performance Unit Program” in Compensation Discussion and Analysis.
(5)	Consists of performance units that will vest on December 31, 2011 only if, and to the extent that, Entergy Corporation attains achievement level as described under “Long-Term Compensation – Performance Unit Program” in Compensation Discussion and Analysis.
(6)	Consists of restricted units granted under the 2007 Equity Ownership Plan. 8,000 units vest on each of January 25, 2011, 2012 and 2013.

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(7)	Consists of restricted units granted under the 2007 Equity Ownership Plan 50,000 of which will vest on December 3, 2011 and the remaining 50,000 will vest on December 3, 2012.
(8)	Consists of restricted units granted under the 2007 Equity Ownership Plan which will vest on April 8, 2013.

2010 Option Exercises and Stock Vested

The following table provides information concerning each exercise of stock options and each vesting of stock during 2010 for the Named Executive Officers.

	Options Awards		Stock Awards
(a) Name	(b) Number of Shares Acquired on Exercise (#)	(c) Value Realized on Exercise ($)	(d) Number of Shares Acquired on Vesting (#) (1)	(e) Value Realized on Vesting ($)

Theodore H. Bunting, Jr.	-	-	140	$11,210

E. Renae Conley	-	-	140	$11,210

Leo P. Denault	13,154	$418,646	390	$31,227

Joseph F. Domino	-	-	70	$5,605

Haley R. Fisackerly	-	-	58	$4,644

J. Wayne Leonard	330,600	$13,922,296	1,650	$132,116

Hugh T. McDonald	-	-	70	$5,605

William M. Mohl	-	-	82	$6,566

Charles L. Rice, Jr.	-	-	-	-

Richard J. Smith	47,068	$1,869,543	390	$31,227

Roderick K. West	-	-	123	$9,849

(1)	Represents the vesting of performance units for the 2008 - 2010 performance cycle (payable solely in cash based on the closing stock price of Entergy Corporation on the last day of the performance period) under the Performance Unit Program.

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2010 Pension Benefits

The following table shows the present value as of December 31, 2010, of accumulated benefits payable to each of the Named Executive Officers, including the number of years of service credited to each Named Executive Officer, under the retirement plans sponsored by Entergy Corporation, determined using interest rate and mortality rate assumptions set forth in Note 11 to the Financial Statements. Information regarding these retirement plans is included in Compensation Discussion & Analysis under the heading, “Benefits, Perquisites, Agreements and Post-Retirement Plans - Pension Plan, Pension Equalization Plan, and System Executive Retirement Plan.” In addition, this section includes information regarding early retirement options under the plans.

Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit	Payments During 2010
Theodore H. Bunting, Jr.	Non-qualified System Executive Retirement Plan	22.86	$1,773,400	$ -
	Qualified defined benefit plan	22.86	$418,700	$ -

E. Renae Conley	Non-qualified System Executive Retirement Plan	11.83	$1,575,800	$ -
	Qualified defined benefit plan	11.83	$260,300	$ -

Leo P. Denault (1)	Non-qualified System Executive Retirement Plan	26.83	$3,717,200	$ -
	Qualified defined benefit plan	11.83	$206,600	$ -

Joseph F. Domino (2)	Non-qualified System Executive Retirement Plan	40.56	$1,657,100	$ -
	Qualified defined benefit plan	37.13	$1,180,000	$ -

Haley R. Fisackerly	Non-qualified System Executive Retirement Plan	15.08	$425,000	$ -
	Qualified defined benefit plan	15.08	$198,700	$ -

J. Wayne Leonard (3)	Non-qualified supplemental retirement plan benefit	12.68	$23,709,800	$ -
	Qualified defined benefit plan	12.68	$360,800	$ -

Hugh T. McDonald (2)	Non-qualified System Executive Retirement Plan	28.93	$1,020,800	$ -
	Qualified defined benefit plan	27.44	$514,300	$ -

William M. Mohl	Non-qualified System Executive Retirement Plan	8.44	$435,100	$ -
	Qualified defined benefit plan	8.44	$148,600	$ -

Charles L. Rice, Jr.	Non-qualified System Executive Retirement Plan	1.47	$15,900	$ -
	Qualified defined benefit plan	1.47	$18,800	$ -

Richard J. Smith (4)	Non-qualified Pension Equalization Plan	34.30	$4,241,200	$ -
	Qualified defined benefit plan	11.34	$308,800	$ -

Roderick K. West	Non-qualified System Executive Retirement Plan	11.75	$504,000	$ -
	Qualified defined benefit plan	11.75	$128,200	$ -

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(1)	During 2006, Mr. Denault entered into an agreement granting an additional 15 years of service under the non-qualified System Executive Retirement Plan if he continues to work for an Entergy System company employer until age 55. The additional 15 years of service increases the present value of his benefit by $1,483,800.
(2)	Service under the non-qualified System Executive Retirement Plan is granted from date of hire. Qualified plan benefit service is granted from the later of date of hire or plan participation date.
(3)	Pursuant to his retention agreement, Mr. Leonard is entitled to a non-qualified supplemental retirement benefit in lieu of participation in Entergy Corporation’s non-qualified supplemental retirement plans such as the System Executive Retirement Plan or the Pension Equalization Plan. Mr. Leonard may separate from employment without a reduction in his non-qualified supplemental retirement benefit.
(4)	Mr. Smith entered into an agreement granting 22.92 additional years of service under the non-qualified Pension Equalization Plan providing an additional $1,031,400 above the accumulated benefit he would receive under the non-qualified System Executive Retirement Plan.

Qualified Retirement Benefits

The qualified retirement plan is a funded defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of Entergy System companies. All Named Executive Officers are participants in this plan. The pension plan provides a monthly benefit payable for the participant’s lifetime beginning at age 65 and equal to 1.5% of the participant’s five-year final average monthly eligible earnings times such participant’s years of service. Participants are 100% vested in their benefit upon completing 5 years of vesting service.

Normal retirement under the plan is age 65. Employees who terminate employment prior to age 55 may receive a reduced deferred vested retirement benefit payable as early as age 55 that is actuarially equivalent to the normal retirement benefit (i.e., reduced by 7% per year for the first 5 years preceding age 65, and reduced by 6% for each additional year thereafter). Employees who are at least age 55 with 10 years of vesting service upon termination from employment are entitled to a subsidized early retirement benefit beginning as early as age 55. The subsidized early retirement benefit is equal to the normal retirement benefit reduced by 2% per year for each year that early retirement precedes age 65.

Mr. Domino, Mr. Leonard and Mr. Smith are eligible for subsidized early retirement benefits.

Non-qualified Retirement Benefits

The Named Executive Officers are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan and the System Executive Retirement Plan. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, each described below and in Compensation Discussion and Analysis, an executive is typically enrolled in one or more plans but only paid the amount due under the plan that provides the highest benefit. In general, upon disability, participants in the Pension Equalization Plan and the System Executive Retirement Plan remain eligible for continued service credits until recovery or retirement. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant’s accrued benefit.

The Pension Equalization Plan

All of the Named Executive Officers (with the exception of Mr. Leonard) are participants in the Pension Equalization Plan. The benefit provisions are substantially the same as the qualified retirement plan but provide two additional benefits: (a) “restorative benefits” intended to offset limitations on certain earnings that may be considered in connection with the qualified retirement plan and (b) supplemental credited service (if granted to an individual participant). The benefits under this plan are offset by benefits payable from the qualified retirement plan and may be offset by prior employer benefits. Participants receive their Pension Equalization Plan benefit in the form of a single sum cash distribution. The Pension Equalization Plan benefit attributable to supplemental credited service is not vested until age 65. Subject to the approval of the Entergy System company employer, an employee who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Internal Revenue Code Section 409A. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits.

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The System Executive Retirement Plan

All Named Executive Officers (except Mr. Leonard) are participants in the System Executive Retirement Plan. The System Executive Retirement Plan provides for a single sum payment at age 65, as further described in Compensation Discussion and Analysis. The System Executive Retirement Plan benefit is not vested until age 65. Subject to the approval of the Entergy System company employer, an employee who terminates his or her employment prior to age 65 may be vested in the System Executive Retirement Plan benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Internal Revenue Code Section 409A. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits. Further, in the event of a change in control, participants whose employment is terminated without “Cause” or for “Good Reason,” as defined in the Plan are also eligible for a subsidized lump sum benefit payment, even if they do not currently meet the age or service requirements for early retirement under that plan or have company permission to separate from employment. Such lump sum benefit is payable generally at separation from service unless delayed 6 months under Internal Revenue Code Section 409A.

Mr. Leonard’s Non-qualified Supplemental Retirement Benefit

Mr. Leonard’s retention agreement provides that if his employment with the Company is terminated for any reason other than for cause (as defined below under “Potential Payments Upon Termination or Change in Control”), he will be entitled to a non-qualified supplemental retirement benefit in lieu of participation in Entergy Corporation’s non-qualified supplemental retirement plans such as the System Executive Retirement Plan or the Pension Equalization Plan. Mr. Leonard’s non-qualified supplemental retirement benefit is calculated as a single life annuity equal to 60% of his final three-year average compensation (as described in the description of the System Executive Retirement Plan included in the Compensation Discussion and Analysis), reduced to account for benefits payable to Mr. Leonard under Entergy Corporation’s and a former employer’s qualified pension plans. The benefit is payable in a single lump sum. Because Mr. Leonard has already attained the age of 55, he is currently entitled under his retention agreement to his non-qualified supplemental retirement benefit if he were to leave Entergy System company employment other than as the result of a termination for cause.

Additional Information

For a description of the material terms and conditions of payments and benefits available under the retirement plans, including each plan’s normal retirement payment and benefit, benefit formula and eligibility standards, specific elements of compensation included in applying the payment and benefit formula, and Entergy Corporation’s policies with regard to granting extra years of credited service, see “Compensation Discussion and Analysis -- Benefits, Perquisites, Agreements and Post-Termination Plans -- Pension Plan, Pension Equalization Plan and System Executive Retirement Plan.” For a discussion of the relevant assumptions used in valuing these liabilities, see Note 11 to the Financial Statements.

2010 Non-qualified Deferred Compensation

The following tables provide information regarding the Executive Deferred Compensation Plan, the Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (the 1998 Equity Ownership Plan) and the 2007 Equity Ownership Plan, which allow for the deferral of compensation for the Named Executive Officers. As of December 31, 2009 none of the Named Executive Officers had a deferred compensation balance remaining in the Equity Ownership Plan. For additional information, see “Benefits, Perquisites, Agreements and Post-Termination Plans - Executive Deferred Compensation” in Compensation Discussion and Analysis. All Named Executive Officers are eligible to participate in the deferral programs.

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Additionally, as of December 31, 2010, Mr. Leonard had a deferred account balance under a frozen Defined Contribution Restoration Plan. These amounts are deemed invested, as chosen by the participant, in certain of the T. Rowe Price investment funds also available to participants under the qualified Savings Plan. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.

All deferrals are credited to the applicable Entergy System company employer’s non-funded liability account. Depending on the plan under which the deferral is made, the Named Executive Officers may elect investment in either phantom Entergy Corporation common stock or one or more of several investment options available under the Savings Plan. Within limitations of the program, participating Named Executive Officers may move funds from one deemed investment option to another. The participating Named Executive Officers do not have the ability to withdraw funds from the deemed investment accounts except within the terms provided in their deferral elections. Within the limitations prescribed by law as well as the plan, participating Named Executive Officers with deferrals under the Executive Deferred Compensation Plan and/or the equity plans have the option to make a successive deferral of these funds. Assuming a Named Executive Officer does not elect a successive deferral, the Entergy System company employer of the participant is obligated to pay the amount credited to the participant’s account at the earlier of deferral receipt date or separation from service. These payments are paid out of the general assets of the employer and are payable in a lump sum.

Executive Deferred Compensation Plan

Name (a)	Executive Contributions in 2010 (b)	Registrant Contributions in 2010 (c)	Aggregate Earnings in 2010 (1) (d)	Aggregate Withdrawals/ Distributions (e)	Aggregate Balance at December 31, 2010 (2) (f)

J. Wayne Leonard	$ -	$ -	$106	($204,006)	$ -

(1)	Amounts in this column are not included in the Summary Compensation Table.

Defined Contribution Restoration Plan

Name (a)	Executive Contributions in 2010 (b)	Registrant Contributions in 2010 (c)	Aggregate Earnings in 2010 (1) (d)	Aggregate Withdrawals/ Distributions (e)	Aggregate Balance at December 31, 2010 (f)

J. Wayne Leonard	$ -	$ -	($22,567)	$ -	$210,098

(1)	Amounts in this column are not included in the Summary Compensation Table.

Potential Payments upon Termination or Change in Control

Estimated Payments

The tables below reflect the amount of compensation each named executive officer would receive upon the occurrence of the specified separation triggering events, based on available programs and specific agreements with each executive. The tables assume the separation was effective on December 31, 2010, the last business day of the last fiscal year, and the stock price of Entergy Corporation common stock is $70.83, which was the closing market price on such date.

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Theodore H. Bunting, Jr

Senior Vice President, Chief Accounting Officer

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Senior Vice President, Chief Accounting Officer would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (7)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$1,121,434
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	---	$94,440	$94,440	$141,660	$141,660
2010-2012 Performance Unit Program		---	---	---	---	$51,942	$51,942	$155,826	$155,826
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	$23,730
280G Tax Gross-up	(8)	---	---	---	---	---	---	---	---

(1)	In addition to the payments and benefits in the table, if Mr. Bunting's employment were terminated under certain conditions relating to a change in control, Mr. Bunting also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits see "2010 Pension Benefits." If Mr. Bunting's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.
(2)	In the event of a termination related to a change in control, Mr. Bunting would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to two times the sum of his base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 60% target opportunity and a base salary of $350,448 was assumed.
(3)	In the event of a termination related to a change in control, Mr. Bunting would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. Bunting's awards were calculated as follows: 2009 - 2011 Plan – 2,000 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 2,200 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of disability or a change in control, all of Mr. Bunting's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Bunting exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. Bunting’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Bunting’s stock options.

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(5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Bunting would be eligible to receive Company- subsidized COBRA benefits for 18 months.
(6)	As of December 31, 2010, compensation and benefits available to Mr. Bunting under this scenario are substantially the same as available with a voluntary resignation.
(7)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

E. Renae Conley

Executive Vice President, Human Resources & Administration

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Executive Vice President, Human Resources & Administration would have been entitled to receive as a result of a termination of her employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (7)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$1,360,000
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	---	$94,440	$94,440	$141,660	$141,660
2010-2012 Performance Unit Program		---	---	---	---	$51,942	$51,942	$155,826	$155,826
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	$7,896
280G Tax Gross-up	(8)	---	---	---	---	---	---	---	---

(1)	In addition to the payments and benefits in the table, if Ms. Conley's employment were terminated under certain conditions relating to a change in control, Ms. Conley also would have been entitled to receive her vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits see "2010 Pension Benefits." If Ms. Conley’s employment were terminated for cause, she would forfeit her benefit under the System Executive Retirement Plan.
(2)	In the event of a termination related to a change in control, Ms. Conley would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to two times the sum of her base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 60% target opportunity and a base salary of $425,000 was assumed.
(3)	In the event of a termination related to a change in control, Ms. Conley would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to her performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Ms. Conley’s awards were calculated as follows: 2009 - 2011 Plan – 2,000 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 2,200 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.

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(4)	In the event of death, disability or a change in control, all of Ms. Conley's unvested stock options would immediately vest. In addition, she would be entitled to exercise her stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Ms. Conley exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Ms. Conley’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Ms. Conley’s stock options.
(5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Conley would be eligible to receive Company- subsidized COBRA benefits for 18 months.
(6)	As of December 31, 2010, compensation and benefits available to Ms. Conley under this scenario are substantially the same as available with a voluntary resignation.
(7)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-ups.

Leo P. Denault

Executive Vice President and Chief Financial Officer

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Executive Vice President and Chief Financial Officer would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (8)	Disability	Death	Change in Control (9)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	$3,202,290	---	---	---	---	$3,202,290
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	$371,858	---	$371,858	$371,858	---	$371,858
2010-2012 Performance Unit Program		---	---	$371,858	---	$371,858	$371,858	---	$371,858
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Unvested Restricted Units	(5)	---	---	$1,699,920	---	$1,699,920	$1,699,920	---	$1,699,920
COBRA Benefits	(6)	---	---	$13,962	---	---	---	---	---
Medical and Dental Benefits	(7)	---	---	---	---	---	---	---	$13,962
280G Tax Gross-up	(10)	---	---	---	---	---	---	---	---

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(1)	In addition to the payments and benefits in the table, Mr. Denault also would have been entitled to receive his vested pension benefits. If Mr. Denault’s employment were terminated under certain conditions relating to a change in control, he would also be eligible for early retirement benefits. For a description of these benefits, see “2010 Pension Benefits.” In addition, Mr. Denault is subject to the following provisions: · Retention Agreement. Mr. Denault’s retention agreement provides that, unless his employment is terminated for cause, he will be granted an additional 15 years of service under the System Executive Retirement Plan if he continues to work for an Entergy System company employer until age 55. Because Mr. Denault had not reached age 55 as of December 31, 2010, he is only entitled to this supplemental credited service and System Executive Retirement Plan supplemental benefits in the event of his death or disability. · System Executive Retirement Plan. If Mr. Denault’s employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan. In the event of a termination related to a change in control, pursuant to the terms of the System Executive Retirement Plan, Mr. Denault would be eligible for subsidized retirement (but not the additional 15 years of service) upon his separation of service even if he does not then meet the age or service requirements for early retirement under the System Executive Retirement Plan or have company permission to separate from employment.
(2)	In the event of a termination (not due to death or disability) by Mr. Denault for good reason or by the Company not for cause (regardless of whether there is a change in control), Mr. Denault would be entitled to receive, pursuant to his retention agreement, a lump sum severance payment equal to 2.99 times the sum of: his annual base salary plus the greater of his annual incentive award under the Executive Incentive Plan for the calendar year immediately preceding the calendar year in which Mr. Denault’s termination date occurs or (ii) Mr. Denault’s Executive Incentive Plan target award for the calendar year in which the effective date of the Agreement occurred (i.e., 2006). For purposes of this table, a base salary of $630,000 and target award of 70% are assumed.
(3)	In the event of a termination due to death or disability, by Mr. Denault for good reason, or by the Company not for cause (in all cases, regardless of whether there is a change in control), Mr. Denault would have forfeited his performance units for all open performance periods and would have been entitled to receive a single-sum severance payment pursuant to his retention agreement that would not be based on any outstanding performance periods. The payment would be calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault's severance payment was calculated by taking an average of the target performance units from the 2006-2008 Performance Unit Program (6,000 units) and the 2007-2009 Performance Unit Program (4,500 units). This average number of units (5,250 units) multiplied by the closing price of Entergy stock on December 31, 2010 ($70.83) would equal a severance payment of $371,858 for the forfeited performance programs.
(4)	In the event of his death, disability, termination by Mr. Denault for good reason or by the Company not for cause (regardless of whether there is a change in control), all of Mr. Denault’s unvested stock options would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, it was assumed that Mr. Denault exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. Denault’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Denault’s stock options.
(5)	Mr. Denault’s 24,000 restricted units vest 1/3 on January 25, 2011, 1/3 on January 25, 2012 and 1/3 on January 25, 2013, provided he remains a full-time System Company employee through each such vesting date. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of a change in control, Mr. Denault’s death or disability, or termination of employment by Mr. Denault for good reason or by the Company not for cause (regardless of whether there is a change in control).
(6)	Pursuant to his retention agreement, in the event of a termination by Mr. Denault for good reason or by the Company not for cause, Mr. Denault would be eligible to receive Company-subsidized COBRA benefits for 18 months.

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(7)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Denault would be eligible to receive Company-subsidized medical and dental benefits for 18 months.
(8)	As of December 31, 2010, Mr. Denault is not eligible for retirement.
(9)	The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments upon a change in control.
(10)	In December of 2010, Mr. Denault voluntarily agreed to amend his retention agreement to eliminate excise tax gross up payments.

Under the terms of Mr. Denault’s retention agreement, Entergy may terminate his employment for cause upon Mr. Denault’s:

·	continuing failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Personnel Committee;

·	willfully engaging in conduct that is demonstrably and materially injurious to Entergy;

·	conviction of or entrance of a plea of guilty or nolo contendere to a felony or other crime that has or may have a material adverse effect on his ability to carry out his duties or upon Entergy’s reputation;

·	material violation of any agreement that he has entered into with Entergy; or

·	unauthorized disclosure of Entergy’s confidential information.

Mr. Denault may terminate his employment for good reason upon:

·	the substantial reduction in the nature or status of his duties or responsibilities;

·	a reduction of 5% or more in his base salary as in effect on the date of the retention agreement;

·	the relocation of his principal place of employment to a location other than the corporate headquarters;

the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, stock options, restricted stock, stock appreciation rights, incentive compensation, bonus and other plans on a basis not materially less favorable than enjoyed at the time of the retention agreement (other than changes similarly affecting all senior executives);

the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him under any of the pension, savings, life insurance, medical, health and accident, disability or vacation plans at the time of the retention agreement (other than changes similarly affecting all senior executives); or

·	any purported termination of his employment not taken in accordance with his retention agreement.

Mr. Denault may terminate his employment for good reason in the event of a change in control upon:

·	the substantial reduction or alteration in the nature or status of his duties or responsibilities;

·	a reduction in his annual base salary;

·	the relocation of his principal place of employment to a location more than 20 miles from his current place of employment;

·	the failure to pay any portion of his compensation within seven days of its due date;

·	the failure to continue in effect any compensation plan in which he participates and which is material to his total compensation, unless other equitable arrangements are made;

the failure to continue to provide benefits substantially similar to those that he currently enjoys under any of the pension, savings, life insurance, medical, health and accident or disability plans, or Entergy taking of any other action which materially reduces any of those benefits or deprives him of any material fringe benefits that he currently enjoys;

·	the failure to provide him with the number of paid vacation days to which he is entitled in accordance with the normal vacation policy; or

·	any purported termination of his employment not taken in accordance with his retention agreement

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Joseph F. Domino

President & CEO - Entergy Texas

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and CEO – Entergy Texas would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (7)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$476,631
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	$42,498	$42,498	$42,498	$63,747	$63,747
2010-2012 Performance Unit Program		---	---	---	$23,610	$23,610	$23,610	$70,830	$70,830
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	---
280G Tax Gross-up	(8)	---	---	---	---	---	---	---	---

(1)	In addition to the payments and benefits in the table, Mr. Domino would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available see "2010 Pension Benefits." In the event of a termination related to a change in control, pursuant to the terms of the System Executive Retirement Plan, Mr. Domino would be eligible for subsidized early retirement even if he does not have company permission to separate from employment. If Mr. Domino’s employment were terminated for cause, he would not receive a benefit under the System Executive Retirement Plan.
(2)	In the event of a termination related to a change in control, Mr. Domino would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to one time the sum of base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 50% target opportunity and a base salary of $317,754 was assumed.
(3)	In the event of a termination related to a change in control, Mr. Domino would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. Domino’s awards were calculated as follows: 2009 - 2011 Plan – 900 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 1,000 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of retirement, death, disability or a change in control, all of Mr. Domino's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Domino exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. Domino’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Domino’s stock options.

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(5)	Upon retirement Mr. Domino would be eligible for retiree medical and dental benefits, the same as all other retirees. Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Domino would not be eligible to receive Entergy subsidized COBRA benefits.
(6)	As of December 31, 2010, compensation and benefits available to Mr. Domino under this scenario are substantially the same as available with a voluntary resignation. For information regarding these vested benefits, see the Pension Benefits table included in this Form 10-K.
(7)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

Haley R. Fisackerly

President & CEO - Entergy Mississippi

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and CEO - Entergy Mississippi would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (7)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$385,000
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	---	$42,498	$42,498	$63,747	$63,747
2010-2012 Performance Unit Program		---	---	---	---	$23,610	$23,610	$70,830	$70,830
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	$15,820
280G Tax Gross-up	(8)	---	---	---	---	---	---	---	---

(1)

In addition to the payments and benefits in the table, if Mr. Fisackerly's employment were terminated under certain conditions relating to a change in control, Mr. Fisackerly also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits see "2010 Pension Benefits." If Mr. Fisackerly's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a termination related to a change in control, Mr. Fisackerly would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to one time the sum of his base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $275,000 was assumed.

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(3)	In the event of a termination related to a change in control, Mr. Fisackerly would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. Fisackerly's awards were calculated as follows: 2009 - 2011 Plan – 900 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 1,000 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of death, disability or a change in control, all of Mr. Fisackerly's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Fisackerly exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. Fisackerly’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Fisackerly’s stock options.
(5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Fisackerly would be eligible to receive Entergy- subsidized COBRA benefits for 12 months.
(6)	As of December 31, 2010, compensation and benefits available to Mr. Fisackerly under this scenario are substantially the same as available with a voluntary resignation.
(7)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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J. Wayne Leonard

Chairman and Chief Executive Officer

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which Entergy's Chairman and Chief Executive Officer would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (8)	Disability	Death	Change in Control (9)	Termination Related to a Change in Control

Annual Incentive Payment	(2)	---	---	---	---	---	---	---	$3,099,600
Severance Payment	(3)	---	---	---	---	---	---	---	$8,495,487
Performance Units:	(4)
2009-2011 Performance Unit Program		---	---	---	$1,062,450	$1,062,450	$1,062,450	---	$2,029,280
2010-2012 Performance Unit Program		---	---	---	$526,503	$526,503	$526,503	---	$2,029,280
Unvested Stock Options	(5)	---	---	---	---	---	---	---	---
Unvested Restricted Units	(6)	---	---	$7,083,000	---	$7,083,000	$7,083,000	---	$7,083,000
Medical and Dental Benefits	(7)	---	---	---	---	---	---	---	---
280G Tax Gross-up	(10)	---	---	---	---	---	---	---	---

(1)	In addition to the payments and benefits in the table, Mr. Leonard would have been eligible to retire and entitled to receive his vested pension benefits. However, a termination “for cause” would have resulted in forfeiture of Mr. Leonard’s supplemental retirement benefit. Mr. Leonard is not entitled to additional pension benefits upon the occurrence of a change in control without termination of employment. For additional information regarding these vested benefits and awards, see “2010 Pension Benefits.”
(2)	In the event of a termination related to a change in control, Mr. Leonard would have been entitled under his retention agreement to receive a lump sum severance payment equal to the product of Mr. Leonard’s average maximum annual bonus opportunity under the Executive Incentive Plan for the Company’s two calendar years immediately preceding the calendar year in which his termination occurs. For purposes of this table, the award was calculated at 200% of target opportunity and a base salary of $1,291,500.
(3)	In the event of a termination related to a change in control, Mr. Leonard would have been entitled to receive pursuant to his retention agreement a lump sum severance payment equal to the sum of 2.99 times the sum of his (a) base salary plus (b) average Executive Incentive Plan award at target for the two calendar years immediately preceding the calendar year in which the termination occurs.
(4)	In the event of a termination related to a change in control, including a termination by Mr. Leonard for good reason, by the Company other than cause, disability or death, Mr. Leonard would have forfeited his performance units for all open performance periods and would have been entitled to receive a single sum severance payment pursuant to his retention agreement that would not be based on any outstanding performance periods. The payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Leonard's severance payment was calculated by taking an average of the target performance units from the 2006-2008 Performance Unit Program (33,500 units) and the 2007-2009 Performance Unit Program (23,800 units). This average number of units (28,650 units) multiplied by the closing price of Entergy stock on December 31, 2010 ($70.83) would equal a severance payment of $2,029,280 for the forfeited performance unit programs. With respect to death, disability or retirement the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. 2009 - 2011 Plan – 22,500 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 22,300 performance units at target, assuming a stock price of $70.83

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(5)	In the event of retirement, death, disability or a termination related to a change in control, all of Mr. Leonard’s unvested stock options would immediately vest. In addition, Mr. Leonard would be entitled to exercise any outstanding options during a ten-year term extending from the grant date of the options. For purposes of this table, it was assumed that Mr. Leonard exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the exercise price of each option share. AS of December 31, 2010, the exercise price for all of Mr. Leonard’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Leonard’s stock options.
(6)	Mr. Leonard’s 100,000 restricted units vest in two installments on December 3, 2011 and December 3, 2012. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of a termination related to a change in control, in the event of the termination of his employment by Mr. Leonard for good reason, by the Company other than for cause, or by reason of his death or disability.
(7)	Upon retirement Mr. Leonard would be eligible for retiree medical and dental benefits, the same as all other retirees. Pursuant to his retention agreement, in the event of a termination related to a change in control, Mr. Leonard would not be eligible to receive additional subsidized COBRA benefits.
(8)	As of December 31, 2010, Mr. Leonard is retirement eligible and would retire rather than voluntarily resign. Given this scenario, the compensation and benefits available to Mr. Leonard under retirement are substantially the same as available with a voluntary resignation.
(9)	The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments upon a change in control.
(10)	In December of 2010, amend Mr. Leonard voluntarily agreed to modify his retention agreement to eliminate excise tax gross up.

Under the terms of Mr. Leonard's retention agreement, we may terminate his employment for cause upon Mr. Leonard's:

·	willful and continued failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Board; or

·	willfully engaging in conduct that is demonstrably and materially injurious to us and which results in a conviction of or entrance of a plea of guilty or nolo contendere (essentially a form of plea in which the accused refuses to contest the charges) to a felony.

In the event of a change in control, Mr. Leonard may terminate his employment for good reason upon:

·	the substantial reduction or alteration in the nature or status of his duties or responsibilities;

·	a reduction in his annual base salary;

·	the relocation of his principal place of employment to a location more than 20 miles from his current place of employment;

·	the failure to pay any portion of his compensation within seven days of its due date;

·	the failure to continue in effect any compensation plan in which he participates and which is material to his total compensation, unless other equitable arrangements are made;

the failure to continue to provide benefits substantially similar to those that he currently enjoys under any of the pension, savings, life insurance, medical, health and accident or disability plans, or the taking of any other action which materially reduces any of those benefits or deprives him of any material fringe benefits that he currently enjoys;

·	the failure to provide him with the number of paid vacation days to which he is entitled in accordance with the normal vacation policy; or

·	any purported termination of his employment not taken in accordance with his retention agreement.

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Hugh T. McDonald

President & CEO, Entergy Arkansas

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President & CEO, Entergy Arkansas would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (7)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$483,198
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	---	$42,498	$42,498	$63,747	$63,747
2010-2012 Performance Unit Program		---	---	---	---	$23,610	$23,610	$70,830	$70,830
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	$15,820
280G Tax Gross-up	(8)	---	---	---	---	---	---	---	---

(1)	In addition to the payments and benefits in the table, if Mr. McDonald's employment were terminated under certain conditions relating to a change in control, Mr. McDonald also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits see "2010 Pension Benefits." If Mr. McDonald's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.
(2)	In the event of a termination related to a change in control, Mr. McDonald would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to one time the sum of his base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 50% target opportunity and a base salary of $322,132 was assumed.
(3)	In the event of a termination related to a change in control, Mr. McDonald would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. McDonald’s awards were calculated as follows: 2009 - 2011 Plan – 900 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 1,000 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of death, disability or a termination related to a change in control, all of Mr. McDonald's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. McDonald exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. McDonald’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. McDonald’s stock options.

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(5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. McDonald would be eligible to receive Company- subsidized COBRA benefits for 12 months.
(6)	As of December 31, 2010, compensation and benefits available to Mr. McDonald under this scenario are substantially the same as available with a voluntary resignation.
(7)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

William M. Mohl

President and CEO, Entergy Louisiana

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and CEO, Entergy Louisiana would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (7)	Disability	Death	Change in Control (8)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$910,000
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	---	$68,469	$68,469	$102,704	$102,704
2010-2012 Performance Unit Program		---	---	---	---	$47,220	$47,220	$141,660	$141,660
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Unvested Restricted Units	(5)	---	---	---	---	---	---	---	$127,494
Medical and Dental Benefits	(6)	---	---	---	---	---	---	---	$17,659
280G Tax Gross-up	(9)	---	---	---	---	---	---	---	---

(1)

In addition to the payments and benefits in the table, if Mr. Mohl's employment were terminated under certain conditions relating to a change in control, Mr. Mohl also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits see "2010 Pension Benefits." If Mr. Mohl's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

(2)

In the event of a termination related to a change in control, Mr. Mohl would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to two times the sum of his base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $325,000 was assumed.

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(3)	In the event of a termination related to a change in control, Mr. Mohl would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. Mohl's awards were calculated as follows: 2009 - 2011 Plan – 1,450 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 2,000 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of death, disability or a change in control, all of Mr. Mohl's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Mohl exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. Mohl’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Mohl’s stock options.
(5)	Mr. Mohl’s 3,000 restricted units vest 40% in 2009 and 60% in 2011. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of termination related to a change in control.
(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Mohl would be eligible to receive Company- subsidized COBRA benefits for 18 months.
(7)	As of December 31, 2010, compensation and benefits available to Mr. Mohl under this scenario are substantially the same as available with a voluntary resignation.
(8)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(9)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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Charles L. Rice, Jr.

President & CEO - Entergy New Orleans

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and CEO - Entergy New Orleans would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (7)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$300,000
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	---	$21,249	$21,249	$31,874	$31,874
2010-2012 Performance Unit Program		---	---	---	---	$19,667	$19,667	$59,001	$59,001
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	$880
280G Tax Gross-up	(8)	---	---	---	---	---	---	---	---

(1)	In addition to the payments and benefits in the table, if Mr. Rice's employment were terminated under certain conditions relating to a change in control, Mr. Rice also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits see "2010 Pension Benefits." If Mr. Rice's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.
(2)	In the event of a termination related to a change in control, Mr. Rice would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to one time the sum of his base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 25% target opportunity and a base salary of $240,000 was assumed.
(3)	In the event of a termination related to a change in control, Mr. Rice would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. Rice’s awards were calculated as follows: 2009 - 2011 Plan – 450 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 833 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of death, disability or a change in control, all of Mr. Rice's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Rice exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. Rice’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Rice’s stock options.

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(5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Rice would be eligible to receive Company- subsidized COBRA benefits for 12 months.
(6)	As of December 31, 2010, compensation and benefits available to Mr. Rice under this scenario are substantially the same as available with a voluntary resignation.
(7)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(8)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

Richard J. Smith

President, Entergy Wholesale Commodity Business

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President, Entergy Wholesale Commodity Business would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (7)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$3,278,535
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	$226,656	$226,656	$226,656	$339,984	$339,984
2010-2012 Performance Unit Program		---	---	---	$125,133	$125,133	$125,133	$375,399	$375,399
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	---
280G Tax Gross-up	(8)	---	---	---	---	---	---	---	---
Retention Agreement	(9)	---	---	---	$967,500	---	---	---	---

(1)

In addition to the payments and benefits in the table, Mr. Smith would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see "2010 Pension Benefits." In the event of a termination related to a change in control, pursuant to the terms of the Pension Equalization Plan, Mr. Smith would be eligible for subsidized early retirement even if he does not have company permission to separate from employment. If Mr. Smith's employment were terminated for cause, he would not receive a benefit under the Pension Equalization Plan.

(2)

In the event of a termination related to a change in control, Mr. Smith would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to 2.99 times the sum of his base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 70% target opportunity and a base salary of $645,000 was assumed.

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(3)	In the event of a termination related to a change in control, Mr. Smith would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. Smith's awards were calculated as follows: 2009 - 2011 Plan – 4,800 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 5,300 performance units at target, assuming a stock price of $70.83 With respect to death, disability or retirement the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of retirement, death, disability or a change in control, all of Mr. Smith's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Smith exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. Smith’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. Smith’s stock options.
(5)	Upon retirement Mr. Smith would be eligible for retiree medical and dental benefits, the same as all other retirees. Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Smith would not be eligible to receive additional subsidized COBRA benefits.
(6)	As of December 31, 2010, Mr. Smith is retirement eligible and would retire rather than voluntarily resign. Given that scenario, the compensation and benefits available to Mr. Smith under retirement are substantially the same as available with a voluntary resignation.
(7)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(8)	In December of 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.
(9)	In December 2009, the Company entered into an agreement with Mr. Smith. The agreement provides that Mr. Smith is entitled to receive a lump sum cash payment equal to 1.5 times his base salary as of the date of separation from Entergy if either he (i) remains continuously employed at a management level for 24 months after the date of the public announcement that the Spin Transaction will not occur or (ii) he remains continuously employed in such capacity for at least six (6) months after such date and thereafter retires with the consent of Entergy Corporation’s Chief Executive Officer prior to reaching such 24 months of service. The “no spin” announcement occurred on April 5, 2010. If he retired on December 31, 2010 with permission from Entergy’s Chief Executive Officer, he would have been eligible to receive 1.5 times his base salary. See “Compensation Discussion and Analysis” for a complete description of Mr. Smith’s agreement.

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Roderick K. West

Executive Vice President & Chief Administrative Officer

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Executive Vice President & Chief Administrative Officer would have been entitled to receive as a result of a termination of her employment under various scenarios as of December 31, 2010:

Benefits and Payments Upon Termination (1)		Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (6)	Disability	Death	Change in Control (8)	Termination Related to a Change in Control

Severance Payment	(2)	---	---	---	---	---	---	---	$2,302,300
Performance Units:	(3)
2009-2011 Performance Unit Program		---	---	---	---	$134,577	$134,577	$201,866	$201,866
2010-2012 Performance Unit Program		---	---	---	---	$108,205	$108,205	$324,614	$324,614
Unvested Stock Options	(4)	---	---	---	---	---	---	---	---
Unvested Restricted Units	(7)	---	---	$1,062,450	---	---	---	$1,062,450	$1,062,450
Medical and Dental Benefits	(5)	---	---	---	---	---	---	---	$23,730
280G Tax Gross-up	(9)	---	---	---	---	---	---	---	---

(1)	In addition to the payments and benefits in the table, if Mr. West's employment were terminated under certain conditions relating to a change in control, Mr. West also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits see "2010 Pension Benefits." If Mr. West's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.
(2)	In the event of a termination related to a change in control, Mr. West would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to 2.99 times the sum of his base salary plus annual incentive, calculated using the average annual target opportunity derived under the Executive Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $550,000 was assumed.
(3)	In the event of a termination related to a change in control, Mr. West would have been entitled to receive pursuant to the 2007 Equity Ownership Plan a lump sum payment relating to his performance units under the Performance Unit Program. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. West’s awards were calculated as follows: 2009 - 2011 Plan – 2,850 performance units at target, assuming a stock price of $70.83 2010 - 2012 Plan – 4,583 performance units at target, assuming a stock price of $70.83 With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
(4)	In the event of death, disability or a change in control, all of Mr. West's unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for a ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. West exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2010, and the applicable exercise price of each option share. As of December 31, 2010, the exercise price for all of Mr. West’s unvested options exceeded the closing stock price and accordingly, no amounts are reported in the table with respect to the accelerated vesting of Mr. West’s stock options.

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(5)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. West would be eligible to receive Company- subsidized COBRA benefits for 18 months.
(6)	As of December 31, 2010, compensation and benefits available to Mr. West under this scenario are substantially the same as available with a voluntary resignation.
(7)	Mr. West's 15,000 restricted unit vest 100% in 2013. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of termination for good reason or not for cause and a change in control.
(8)	Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: · All unvested stock options would become immediately exercisable; and · Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that Awards granted after December 30, 2010 require an involuntary termination in order to accelerate vesting or trigger severance payments.
(9)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

In the following sections, additional information is provided regarding certain of the scenarios described in the tables above:

Termination Related to a Change in Control

Under the System Executive Continuity Plan, the Named Executive Officers will be entitled to the benefits described in the tables above in the event of a termination related to a change in control if their employment is terminated other than for cause or if they terminate their employment for good reason, in each case within a period commencing 90 days prior to and ending 24 months following a change in control.

A change in control includes the following events:

·	The purchase of 30% or more of either the common stock or the combined voting power of the voting securities, the merger or consolidation of Entergy Corporation (unless Entergy Corporation's board members constitute at least a majority of the board members of the surviving entity);

·	the merger or consolidation of Entergy Corporation (unless Entergy Corporation's board members constitute at least a majority of the board members of the surviving entity);

·	the liquidation, dissolution or sale of all or substantially all of Entergy Corporation's assets; or

·	a change in the composition of Entergy Corporation's board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation's board at the end of the period.

The proposed separation of the non-utility nuclear business in a tax-free spin-off to Entergy Corporation's shareholders does not constitute a "Change in Control" for purposes of the System Executive Continuity Plan.

Entergy Corporation may terminate a Named Executive Officer's employment for cause under the System Executive Continuity Plan if he or she:

·	fails to substantially perform his duties for a period of 30 days after receiving notice from the board;

·	engages in conduct that is injurious to Entergy Corporation or any of its subsidiaries;

·	is convicted or pleads guilty to a felony or other crime that materially and adversely affects his or her ability to perform his or her duties or Entergy Corporation's reputation;

·	violates any agreement with Entergy Corporation or any of its subsidiaries; or

·	discloses any of Entergy Corporation's confidential information without authorization.

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A Named Executive Officer may terminate employment with Entergy Corporation for good reason under the System Executive Continuity Plan if, without the Named Executive Officer's consent:

·	the nature or status of his or her duties and responsibilities is substantially altered or reduced compared to the period prior to the change in control;

·	his or her salary is reduced by 5% or more;

·	he or she is required to be based outside of the continental United States at somewhere other than the primary work location prior to the change in control;

·	any of his or her compensation plans are discontinued without an equitable replacement;

·	his or her benefits or number of vacation days are substantially reduced; or

·	his or her employment is purported to be terminated other than in accordance with the System Executive Continuity Plan.

In addition to participation in the System Executive Continuity Plan, upon the completion of a transaction resulting in a change in control of Entergy Corporation, benefits already accrued under the System Executive Retirement Plan and Pension Equalization Plan, if any, will become fully vested if the executive is involuntarily terminated without cause or terminates employment for good reason. Any awards granted under the Equity Ownership Plan will become fully vested upon a Change in Control without regard to whether the executive is involuntarily terminated without cause or terminates employment for good reason.

Under certain circumstances, the payments and benefits received by a Named Executive Officer pursuant to the System Executive Continuity Plan may be forfeited and, in certain cases, subject to repayment. Benefits are no longer payable under the System Executive Continuity Plan, and unvested performance units under the Performance Unit Program are subject to forfeiture, if the executive:

·	accepts employment with Entergy Corporation or any of its subsidiaries;

·	elects to receive the benefits of another severance or separation program;

·	removes, copies or fails to return any property belonging to Entergy Corporation or any of its subsidiaries;

·	discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries; or

·	violates their non-competition provision, which generally runs for two years but extends to three years if permissible under applicable law.

Furthermore, if the executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates their non-competition provision, he or she will be required to repay any benefits previously received under the System Executive Continuity Plan.

Termination for Cause

If a Named Executive Officer's employment is terminated for "cause" (as defined in the System Executive Continuity Plans and described above under "Termination Related to a Change in Control"), he or she is generally entitled to the same compensation and separation benefits described below under "Voluntary Resignation" except that all options may no longer be exercisable.

Voluntary Resignation

If a Named Executive Officer voluntarily resigns from an Entergy System company employer, he or she is entitled to all accrued benefits and compensation as of the separation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees. In the case of voluntary resignation, the officer would forfeit all unvested stock options and restricted units as well as any perquisites to which he or she is entitled as an officer. In addition, the officer would forfeit, except as described below, his or her right to receive incentive payments under the Performance Unit Program or the Executive Incentive Plan. If the officer resigns after the completion of an Executive Incentive Plan or Performance Unit Program performance period, he or she could receive a payout under the Performance Unit Program based on the outcome of the performance cycle and could, at the Entergy Corporation's discretion, receive an annual incentive payment under the Executive Incentive Plan. Any vested stock options held by the officer as of the separation date will expire the earlier of ten years from date of grant or 90 days from the last day of active employment.

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Retirement

Under Entergy Corporation's retirement plans, a Named Executive Officer's eligibility for retirement benefits is based on a combination of age and years of service. Normal retirement is defined as age 65. Early retirement is defined under the qualified retirement plan as minimum age 55 with 10 years of service and in the case of the System Executive Retirement Plan and the supplemental credited service under the Pension Equalization Plan, the consent of Entergy System company employer.

Upon a Named Executive Officer's retirement, he or she is generally entitled to all accrued benefits and compensation as of the separation date, including qualified pension benefits and other post-employment benefits consistent with those generally available to salaried employees. The annual incentive payment under the Executive Incentive Plan is pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs. Similarly, payments under the Performance Unit Program for those retiring with a minimum of 12 months of participation are pro-rated based on the actual number of days employed, in each outstanding performance cycle, in which the retirement date occurs. In each case, payments are delivered at the conclusion of each annual or performance cycle, consistent with the timing of payments to active participants in the Executive Incentive Plan and the Performance Unit Program, respectively.

Unvested stock options issued under the Equity Ownership Plan vest on the retirement date and expire ten years from the grant date of the options. Any restricted units held (other than those issued under the Performance Unit Program) by the executive upon his or her retirement are forfeited, and perquisites (other than short-term financial counseling services) are not available following the separation date.

Disability

If a Named Executive Officer's employment is terminated due to disability, he or she generally is entitled to the same compensation and separation benefits described above under "Retirement," except that restricted units may be subject to specific disability benefits (as noted, where applicable, in the tables above).

Death

If a Named Executive Officer dies while actively employed by an Entergy System company employer, he or she generally is entitled to the same compensation and separation benefits described above under "Retirement," except that:

·	all unvested stock options granted prior to January 1, 2007 are forfeited;

·	vested stock options will expire the earlier of ten years from the grant date or three years following the executive's death;

·	restricted units may be subject to specific death benefits (as noted, where applicable, in the tables above).

Compensation of Directors

For information regarding compensation of the directors of Entergy Corporation, see the Proxy Statement under the heading “Director Compensation”, which information is incorporated herein by reference. The Boards of Directors of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas are comprised solely of employee directors who receive no compensation for service as directors.

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Item 12. Security Ownership of Certain Beneficial Owners and Management

Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas. The information with respect to persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation’s outstanding common stock is included under the heading “Stockholders Who Own at Least Five Percent” in the Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.

The following table sets forth the beneficial ownership of Common Stock of Entergy Corporation and stock-based units as of December 31, 2010 for all directors and Named Executive Officers. Unless otherwise noted, each person had sole voting and investment power over the number of shares of Common Stock and stock-based units of Entergy Corporation set forth across from his or her name.

Name	Shares (1)	Options Exercisable Within 60 Days	Stock Units (2)

Entergy Corporation
Maureen S. Bateman*	3,700	-	8,000
W. Frank Blount*	12,834	-	18,400
Leo P. Denault**	10,884	311,799	-
Gary W. Edwards*	900	-	6,231
Alexis Herman*	4,500	-	5,600
Donald C. Hintz*	8,091	260,000	6,000
J. Wayne Leonard*** (3)	360,710	1,679,133	2,966
Stuart L. Levenick*	3,200	-	3,831
Blanche L. Lincoln*	-	-	-
Stewart C. Myers*	738	-	583
James R. Nichols* (3)	8,889	-	19,426
William A. Percy, II*	2,650	-	12,154
Mark T. Savoff**	1,010	173,800	251
Richard J. Smith**	42,272	405,266	-
W. J. Tauzin*	3,100	-	3,693
Gary J. Taylor**	1,454	314,833	-
Steven V. Wilkinson*	4,255	-	5,227
All directors and executive
officers as a group (23 persons)	489,778	3,619,048	92,362

Entergy Arkansas
Theodore H. Bunting, Jr.**	786	49,033	-
Leo P. Denault***	10,884	311,799	-
J. Wayne Leonard**	360,710	1,679,133	2,966
Hugh T. McDonald***	8,672	75,555	-
Mark T. Savoff*	1,010	173,800	251
Richard J. Smith**	42,272	405,266	-
Gary J. Taylor*	1,454	314,833	-
All directors and executive
officers as a group (12 persons)	445,593	3,434,603	3,217

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Name	Shares (1)	Options Exercisable Within 60 Days	Stock Units (2)

Entergy Gulf States Louisiana
Theodore H. Bunting, Jr.**	786	49,033	-
Leo P. Denault***	10,884	311,799	-
J. Wayne Leonard**	360,710	1,679,133	2,966
William M. Mohl***	-	28,800	-
Mark T. Savoff*	1,010	173,800	251
Richard J. Smith**	42,272	405,266	-
Gary J. Taylor*	1,454	314,833	-
All directors and executive
officers as a group (12 persons)	436,921	3,387,848	3,217

Entergy Louisiana
Theodore H. Bunting, Jr.**	786	49,033	-
Leo P. Denault***	10,884	311,799	-
J. Wayne Leonard**	360,710	1,679,133	2,966
William M. Mohl***	-	28,800	-
Mark T. Savoff*	1,010	173,800	251
Richard J. Smith**	42,272	405,266	-
Gary J. Taylor*	1,454	314,833	-
All directors and executive
officers as a group (12 persons)	436,921	3,387,848	3,217

Entergy Mississippi
Theodore H. Bunting, Jr.**	786	49,033	-
Leo P. Denault***	10,884	311,799	-
Haley R. Fisackerly***	1,715	14,033	-
J. Wayne Leonard**	360,710	1,679,133	2,966
Mark T. Savoff*	1,010	173,800	251
Richard J. Smith**	42,272	405,266	-
Gary J. Taylor*	1,454	314,833	-
All directors and executive
officers as a group (12 persons)	438,636	3,373,081	3,217

Entergy New Orleans
Theodore H. Bunting, Jr.**	786	49,033	-
Leo P. Denault**	10,884	311,799	-
J. Wayne Leonard**	360,710	1,679,133	2,966
Charles L. Rice, Jr.***	394	-	-
Richard J. Smith**	42,272	405,266	-
Gary J. Taylor*	1,454	314,833	-
Roderick K. West*	1,949	27,667	-
All directors and executive
officers as a group (12 persons)	437,315	3,359,048	3,217

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Name	Shares (1)	Options Exercisable Within 60 Days	Stock Units (2)

Entergy Texas
Theodore H. Bunting, Jr.**	786	49,033	-
Leo P. Denault***	10,884	311,799	-
Joseph F. Domino***	-	61,533	-
J. Wayne Leonard**	360,710	1,679,133	2,966
Mark T. Savoff*	1,010	173,800	251
Richard J. Smith**	42,272	405,266	-
Gary J. Taylor*	1,454	314,833	-
All directors and executive
officers as a group (12 persons)	436,921	3,420,581	3,217

*	Director of the respective Company
**	Named Executive Officer of the respective Company
***	Director and Named Executive Officer of the respective Company

(1)	The number of shares of Entergy Corporation common stock owned by each individual and by all directors and executive officers as a group does not exceed one percent of the outstanding Entergy Corporation common stock.
(2)	Represents the balances of phantom units each executive holds under the defined contribution restoration plan and the deferral provisions of the Equity Ownership Plan. These units will be paid out in either Entergy Corporation Common Stock or cash equivalent to the value of one share of Entergy Corporation Common Stock per unit on the date of payout, including accrued dividends. The deferral period is determined by the individual and is at least two years from the award of the bonus. For directors of Entergy Corporation the phantom units are issued under the Service Recognition Program for Outside Directors. All non-employee directors are credited with units for each year of service on the Board. In addition, Messrs. Edwards, Hintz and Percy are deferring receipt of their quarterly stock grants. The deferred shares will be settled in units at the end of the deferral period.
(3)	Excludes 4,059 shares that are owned by a charitable foundation that Mr. Nichols controls.

Equity Compensation Plan Information

The following table summarizes the equity compensation plan information as of December 31, 2010. Information is included for equity compensation plans approved by the stockholders and equity compensation plans not approved by the stockholders.

Plan	Number of Securities to be Issued Upon Exercise of Outstanding Options (a)	Weighted Average Exercise Price (b)	Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a)) (c)

Equity compensation plans approved by security holders (1)	9,911,940	$76.56	2,258,812
Equity compensation plans not approved by security holders(2)	1,313,785	$41.40	-
Total	11,225,725	$72.45	2,258,812

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(1)

Includes the Equity Ownership Plan, which was approved by the shareholders on May 15, 1998 and the 2007 Equity Ownership Plan which was approved by Entergy Corporation shareholders on May 12, 2006. 7,000,000 shares of Entergy Corporation common stock can be issued from the 2007 Plan, with no more than 2,000,000 shares available for non-option grants. The Equity Ownership Plan and the 2007 Plan (the “Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors). Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy System employer and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by the Company. The Plans provide for the issuance of stock options, restricted shares, equity awards (units whose value is related to the value of shares of the Common Stock but do not represent actual shares of Common Stock), performance awards (performance shares or units valued by reference to shares of Common Stock or performance units valued by reference to financial measures or property other than Common Stock) and other stock-based awards.

(2)

Entergy has a Board-approved stock-based compensation plan. However, effective May 9, 2003, the Board has directed that no further awards be issued under that plan.

Item 13. Certain Relationships and Related Transactions and Director Independence

For information regarding certain relationships, related transactions and director independence of Entergy Corporation, see the Proxy Statement under the headings “Corporate Governance - Director Independence” and “Transactions with Related Persons,” which information is incorporated herein by reference.

Since December 31, 2009, none of the Subsidiaries or any of their affiliates has participated in any transaction involving an amount in excess of $120,000 in which any director or executive officer of any of the Subsidiaries, any nominee for director, or any immediate family member of the foregoing had a material interest as contemplated by Item 404(a) of Regulation S-K (“Related Party Transactions”).

Entergy Corporation’s Board of Directors has adopted written policies and procedures for the review, approval or ratification of Related Party Transactions. Under these policies and procedures, the Corporate Governance Committee, or a subcommittee of the Board of Directors of Entergy Corporation composed of independent directors, reviews the transaction and either approves or rejects the transaction after taking into account the following factors:

·	Whether the proposed transaction is on terms at least as favorable to Entergy Corporation or the subsidiary as those achievable with an unaffiliated third party;

·	Size of transaction and amount of consideration;

·	Nature of the interest;

·	Whether the transaction involves a conflict of interest;

·	Whether the transaction involves services available from unaffiliated third parties; and

·	Any other factors that the Corporate Governance Committee or subcommittee deems relevant.

The policy does not apply to (a) compensation and Related Party Transactions involving a director or an executive officer solely resulting from that person’s service as a director or employment with the Company so long as the compensation is approved by Entergy’s Board of Directors, (b) transactions involving the rendering of services as a public utility at rates or charges fixed in conformity with law or governmental authority or (c) any other categories of transactions currently or in the future excluded from the reporting requirements of Item 404(a) of Regulation SK.

None of the Subsidiaries are listed issuers. As previously noted, the Boards of Directors of the Subsidiaries are composed solely of employee directors. None of the Boards of Directors of any of the Subsidiaries has any committees.

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EXHIBIT INDEX

The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 15 of Form 10-K.

Some of the agreements included or incorporated by reference as exhibits to this Form 10-K contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of “materiality” that are different from the standard of “materiality” under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.

Entergy acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-K not misleading.

(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

Entergy Gulf States Louisiana

(a) --

Plan of Merger of Entergy Gulf States, Inc. effective December 31, 2007 (2(ii) to Form 8-K15D5 filed January 7, 2008 in 333-148557).

(3) Articles of Incorporation and By-laws

Entergy Corporation

(a) 1 --	Restated Certificate of Incorporation of Entergy Corporation dated October 10, 2006 (3(a) to Form 10-Q for the quarter ended September 30, 2006).

(a) 2 --	By-Laws of Entergy Corporation as amended February 12, 2007, and as presently in effect (3(ii) to Form 8-K filed February 16, 2007 in 1-11299).

System Energy

(b) 1 --	Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399).

(b) 2 --	By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067).

Entergy Arkansas

(c) 1 --	Second Amended and Restated Articles of Incorporation of Entergy Arkansas, effective August 19, 2009 (3 to Form 8-K filed August 24, 2009 in 1-10764).

(c) 2 --	By-Laws of Entergy Arkansas effective November 26, 1999, and as presently in effect (3(ii)(c) to Form 10-K for the year ended December 31, 1999 in 1-10764).

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Entergy Gulf States Louisiana

(d) 1 --	Articles of Organization of Entergy Gulf States Louisiana effective December 31, 2007 (3(i) to Form 8-K15D5 filed January 7, 2008 in 333-148557).

(d) 2 --	Operating Agreement of Entergy Gulf States Louisiana, effective as of December 31, 2007 (3(ii) to Form 8-K15D5 filed January 7, 2008 in 333-148557).

Entergy Louisiana

(e) 1 --	Articles of Organization of Entergy Louisiana effective December 31, 2005 (3(c) to Form 8-K filed January 6, 2006 in 1-32718).

(e) 2 --	Regulations of Entergy Louisiana effective December 31, 2005, and as presently in effect (3(d) to Form 8-K filed January 6, 2006 in 1-32718).

Entergy Mississippi

(f) 1 --	Second Amended and Restated Articles of Incorporation of Entergy Mississippi, effective July 21, 2009 (99.1 to Form 8-K filed July 27, 2009 in 1-31508).

(f) 2 --	By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320).

Entergy New Orleans

(g) 1 --	Amended and Restated Articles of Incorporation of Entergy New Orleans, effective May 8, 2007 (3(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).

(g) 2 --	Amended By-Laws of Entergy New Orleans effective May 8, 2007, and as presently in effect (3(b) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).

Entergy Texas

(h) 1 --	Certificate of Formation of Entergy Texas, effective December 31, 2007 (3(i) to Form 10 filed March 14, 2008 in 000-53134).

(h) 2 --	By-Laws of Entergy Texas effective December 31, 2007 (3(ii) to Form 10 filed March 14, 2008 in 000-53134).

(4)	Instruments Defining Rights of Security Holders, Including Indentures

Entergy Corporation

(a) 1 --	See (4)(b) through (4)(h) below for instruments defining the rights of holders of long-term debt of System Energy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas.

(a) 2 --	Credit Agreement ($3,500,000,000), dated as of August 2, 2007, among Entergy Corporation, the Banks (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), J. P. Morgan Chase Bank, N.A., KeyBank National Association, Lehman Brothers Bank (FSB), Mizuho Corporate Bank, Ltd., Morgan Stanley Bank, Regions Bank, Societe Generale, The Bank of New York, The Bank of Nova Scotia, The Bank of Toyko-Mitsubishi UFJ, Ltd. (New York Branch), The Royal Bank of Scotland plc, Union Bank of California, N.A., Wachovia Bank, National Association and William Street Commitment Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, and ABN AMRO Bank, N.V., as LC Issuing Bank (10(a) to Form 10-Q for the quarter ended June 30, 2007 in 1-11299).

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(a) 3 --	Indenture, dated as of December 1, 2002, between Entergy Corporation and Deutsche Bank Trust Company Americas, as Trustee (4(a)4 to Form 10-K for the year ended December 31, 2002 in 1-11299).

(a) 4 --	Officer’s Certificate for Entergy Corporation relating to 7.06% Senior Notes due March 15, 2011 (4(d) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299).

(a) 5 --	Indenture (For Unsecured Debt Securities), dated as of September 1, 2010, between Entergy Corporation and Wells Fargo Bank, National Association (4.01 to Form 8-K filed September 16, 2010 in 1-11299).

(a) 6 --	Officer’s Certificate for Entergy Corporation relating to 3.625% Senior Notes due September 15, 2015 (4.02(a) to Form 8-K filed September 16, 2010 in 1-11299).

(a) 7 --	Officer’s Certificate for Entergy Corporation relating to 5.125% Senior Notes due September 15, 2020 (4.02(b) to Form 8-K filed September 16, 2010 in 1-11299).

System Energy

(b) 1 --	Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-three Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24 Certificate in 70-5890 (First); B to Rule 24 Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended June 30, 1981 in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382 (Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946 (Seventeenth); A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth); A-2(g) to Rule 24 Certificate dated May 6, 1994 in 70-7946 (Nineteenth); A-2(a)(1) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twentieth); A-2(a)(2) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twenty-first); A-2(a) to Rule 24 Certificate filed October 4, 2002 in 70-9753 (Twenty-second); and 4(b) to Form 10-Q for the quarter ended September 30, 2007 in 1-9067 (Twenty-third)).

(b) 2 --	Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

(b) 3 --	Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

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Entergy Arkansas

Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by seventy Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate dated December 1, 1982 in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate dated February 17, 1983 in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate dated December 5, 1984 in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate dated November 30, 1990 in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate dated January 24, 1991 in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first); 4(a) to Form 10-Q for the quarter ended June 30, 1994 in 1-10764 (Fifty-second); C-2 to Form U5S for the year ended December 31, 1995 (Fifty-third); C-2(a) to Form U5S for the year ended December 31, 1996 (Fifty-fourth); 4(a) to Form 10-Q for the quarter ended March 31, 2000 in 1-10764 (Fifty-fifth); 4(a) to Form 10-Q for the quarter ended September 30, 2001 in 1-10764 (Fifty-sixth); C-2(a) to Form U5S for the year ended December 31, 2001 (Fifty-seventh); 4(c)1 to Form 10-K for the year December 31, 2002 in 1-10764 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Fifty-ninth); 4(f) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixtieth); 4(h) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixty-first); 4(e) to Form 10-Q for the quarter ended September 30, 2004 in 1-10764 (Sixty-second); 4(c)1 to Form 10-K for the year December 31, 2004 in 1-10764 (Sixty-third); C-2(a) to Form U5S for the year ended December 31, 2004 (Sixty-fourth); 4(c) to Form 10-Q for the quarter ended June 30, 2005 in 1-10764 (Sixty-fifth); 4(a) to Form 10-Q for the quarter ended June 30, 2006 in 1-10764 (Sixty-sixth); 4(b) to Form 10-Q for the quarter ended June 30, 2008 in 1-10764 (Sixty-seventh); 4(c)1 to Form 10-K for the year ended December 31, 2008 in 1-10764 (Sixty-eighth); 4.06 to Form 8-K dated October 8, 2010 in 1-10764 (Sixty-ninth); and 4.06 to Form 8-K dated November 12, 2010 in 1-10764 (Seventieth)).

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Entergy Gulf States Louisiana

(d) 1 --	Indenture of Mortgage, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-27031 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-27031 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-27031 (Fifty-third); 4 to Form 8-K dated July 29, 1992 in 1-27031 (Fifth-fourth); 4 to Form 10-K dated December 31, 1992 in 1-27031 (Fifty-fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-27031 (Fifty-sixth); 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); A-2(a) to Rule 24 Certificate dated June 23, 2000 in 70-8721 (Fifty-ninth); A-2(a) to Rule 24 Certificate dated September 10, 2001 in 70-9751 (Sixtieth); A-2(b) to Rule 24 Certificate dated November 18, 2002 in 70-9751 (Sixty-first); A-2(c) to Rule 24 Certificate dated December 6, 2002 in 70-9751 (Sixty-second); A-2(d) to Rule 24 Certificate dated June 16, 2003 in 70-9751 (Sixty-third); A-2(e) to Rule 24 Certificate dated June 27, 2003 in 70-9751 (Sixty-fourth); A-2(f) to Rule 24 Certificate dated July 11, 2003 in 70-9751 (Sixty-fifth); A-2(g) to Rule 24 Certificate dated July 28, 2003 in 70-9751 (Sixty-sixth); A-3(i) to Rule 24 Certificate dated November 4, 2004 in 70-10158 (Sixty-seventh); A-3(ii) to Rule 24 Certificate dated November 23, 2004 in 70-10158 (Sixty-eighth); A-3(iii) to Rule 24 Certificate dated February 16, 2005 in 70-10158 (Sixty-ninth); A-3(iv) to Rule 24 Certificate dated June 2, 2005 in 70-10158 (Seventieth); A-3(v) to Rule 24 Certificate dated July 21, 2005 in 70-10158 (Seventy-first); A-3(vi) to Rule 24 Certificate dated October 7, 2005 in 70-10158 (Seventy-second); A-3(vii) to Rule 24 Certificate dated December 19, 2005 in 70-10158 (Seventy-third); 4(a) to Form 10-Q for the quarter ended March 31, 2006 in 1-27031 (Seventy-fourth); 4(iv) to Form 8-K15D5 dated January 7, 2008 in 333-148557 (Seventy-fifth); 4(a) to Form 10-Q for the quarter ended June 30, 2008 in 333-148557 (Seventy-sixth); 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K dated October 1, 2010 in 0-20371 (Seventy-eighth); 4(c) to Form 8-K filed October 12, 2010 in 0-20371 (Seventy-ninth); and 4(f) to Form 8-K filed October 12, 2010 in 0-20371 (Eightieth)).

(d) 2 --	Indenture, dated March 21, 1939, accepting resignation of The Chase National Bank of the City of New York as trustee and appointing Central Hanover Bank and Trust Company as successor trustee (B-a-1-6 in Registration No. 2-4076).

(d) 3 --	Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031).

(d) 4 --	Credit Agreement ($200,000,000), dated as of August 2, 2007, among Entergy Gulf States, Inc., the Banks (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), JPMorgan Chase Bank, N.A., KeyBank National Association, Mizuho Corporate Bank, Ltd., Morgan Stanley Bank, The Bank of New York, The Royal Bank of Scotland plc, and Wachovia Bank, National Association), Citibank, N.A., as Administrative Agent, and the LC Issuing Banks (10(c) to Form 10-Q for the quarter ended June 30, 2007 in 1-27031).

(d) 5 --	Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134).

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Entergy Louisiana

(e) 1 --	Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by seventy Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412 (Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth); C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919 (Twenty-third); C-1 to Rule 24 Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635 (Thirtieth); C-1 to Rule 24 Certificate in 70-6834 (Thirty-first); C-1 to Rule 24 Certificate in 70-6886 (Thirty-second); C-1 to Rule 24 Certificate in 70-6993 (Thirty-third); C-2 to Rule 24 Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1988 in 1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d) to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule 24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24 Certificate in 70-7822 (Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822 (Forth-seventh); A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth); A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth); A-4(c) to Rule 24 Certificate dated September 28, 1994 in 70-7653 (Fiftieth); A-2(a) to Rule 24 Certificate dated April 4, 1996 in 70-8487 (Fifty-first); A-2(a) to Rule 24 Certificate dated April 3, 1998 in 70-9141 (Fifty-second); A-2(b) to Rule 24 Certificate dated April 9, 1999 in 70-9141 (Fifty-third); A-3(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141 (Fifty-fourth); A-2(c) to Rule 24 Certificate dated June 2, 2000 in 70-9141 (Fifty-fifth); A-2(d) to Rule 24 Certificate dated April 4, 2002 in 70-9141 (Fifty-sixth); A-3(a) to Rule 24 Certificate dated March 30, 2004 in 70-10086 (Fifty-seventh); A-3(b) to Rule 24 Certificate dated October 15, 2004 in 70-10086 (Fifty-eighth); A-3(c) to Rule 24 Certificate dated October 26, 2004 in 70-10086 (Fifty-ninth); A-3(d) to Rule 24 Certificate dated May 18, 2005 in 70-10086 (Sixtieth); A-3(e) to Rule 24 Certificate dated August 25, 2005 in 70-10086 (Sixty-first); A-3(f) to Rule 24 Certificate dated October 31, 2005 in 70-10086 (Sixty-second); B-4(i) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-32718 (Sixty-seventh); 4.08 to Form 8-K dated September 24, 2010 in 1-32718 (Sixty-eighth); 4(c) to Form 8-K filed October 12, 2010 in 1-32718 (Sixty-ninth); and 4.08 to Form 8-K dated November 23, 2010 in 1-32718 (Seventieth)).

(e) 2 --	Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-1 in Registration No. 33-30660), as supplemented by Lease Supplement No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 1, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 2 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).

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(e) 3 --	Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-2 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 2, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 3 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).

(e) 4 --	Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-3 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 3, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 4 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474).

(e) 5 --	Credit Agreement ($200,000,000), dated as of August 2, 2007, among Entergy Louisiana, the Banks (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), JPMorgan Chase Bank, N.A., KeyBank National Association, Mizuho Corporate Bank, Ltd., Morgan Stanley Bank, The Bank of New York, The Royal Bank of Scotland plc, and Wachovia Bank, National Association), Citibank, N.A., as Administrative Agent, and the LC Issuing Banks (10(b) to Form 10-Q for the quarter ended June 30, 2007 in 1-11299).

Entergy Mississippi

(f) 1 --

Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by twenty-seven Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth); A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth); (A-2(l) to Rule 24 Certificate dated April 21, 1995 in 70-7914 (Tenth); A-2(a) to Rule 24 Certificate dated June 27, 1997 in 70-8719 (Eleventh); A-2(b) to Rule 24 Certificate dated April 16, 1998 in 70-8719 (Twelfth); A-2(c) to Rule 24 Certificate dated May 12, 1999 in 70-8719 (Thirteenth); A-3(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719 (Fourteenth); A-2(d) to Rule 24 Certificate dated February 24, 2000 in 70-8719 (Fifteenth); A-2(a) to Rule 24 Certificate dated February 9, 2001 in 70-9757 (Sixteenth); A-2(b) to Rule 24 Certificate dated October 31, 2002 in 70-9757 (Seventeenth); A-2(c) to Rule 24 Certificate dated December 2, 2002 in 70-9757 (Eighteenth); A-2(d) to Rule 24 Certificate dated February 6, 2003 in 70-9757 (Nineteenth); A-2(e) to Rule 24 Certificate dated April 4, 2003 in 70-9757 (Twentieth); A-2(f) to Rule 24 Certificate dated June 6, 2003 in 70-9757 (Twenty-first); A-3(a) to Rule 24 Certificate dated April 8, 2004 in 70-10157 (Twenty-second); A-3(b) to Rule 24 Certificate dated April 29, 2004 in 70-10157 (Twenty-third); A-3(c) to Rule 24 Certificate dated October 4, 2004 in 70-10157 (Twenty-fourth); A-3(d) to Rule 24 Certificate dated January 27, 2006 in 70-10157 (Twenty-fifth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); and 4(b) to Form 10-Q for the quarter ended March 31, 2010 in 1-31508 (Twenty-seventh)).

Entergy New Orleans

(g) 1 --

Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by fifteen Supplemental Indentures (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth); 4(a) to Form 8-K dated April 26, 1995 in 0-5807 (Fifth); 4(a) to Form 8-K dated March 22, 1996 in 0-5807 (Sixth); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4(d) to Form 10-Q for the quarter ended June 30, 2000 in 0-5807 (Eighth); C-5(a) to Form U5S for the year ended December 31, 2000 (Ninth); 4(b) to Form 10-Q for the quarter ended September 30, 2002 in 0-5807 (Tenth); 4(k) to Form 10-Q for the quarter ended June 30, 2003 in 0-5807 (Eleventh); 4(a) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Twelfth); 4(b) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Thirteenth); 4(e) to Form 10-Q for the quarter ended June 30, 2005 in 0-5807 (Fourteenth); and 4.02 to Form 8-K dated November 23, 2010 in 0-5807 (Fifteenth)).

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Entergy Texas

(h) 1 --	Credit Agreement ($200,000,000), dated as of August 2, 2007, among Entergy Gulf States, Inc. the Banks (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), J. P. Morgan Chase Bank, N.A., KeyBank National Association, Mizuho Corporate Bank, Ltd., Morgan Stanley Bank, The Bank of New York, The Royal Bank of Scotland plc, and Wachovia Bank, National Association), Citibank, N.A., as Administrative Agent and LC Issuing Bank (10(c) to Form 10-Q for the quarter ended June 30, 2007 in 1-11299).

(h) 2 --	Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134).

(h) 3 --	Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)2 to Form 10-K for the year ended December 31, 2008 in 0-53134).

(h) 4 --	Officer’s Certificate No. 1-B-1 dated January 27, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)3 to Form 10-K for the year ended December 31, 2008 in 0-53134).

(h) 5 --	Officer’s Certificate No. 2-B-2 dated May 14, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2009 in 1-34360).

(h) 6 --	Officer’s Certificate No. 3-B-3 dated May 18, 2010, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2010 in 1-34360).

(10) Material Contracts

Entergy Corporation

(a) 1 --	Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(a) 2 --	Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-11299).

(a) 3 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).

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(a) 4 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080).

(a) 5 --	Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).

(a) 6 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 to Form 10-K for the year ended December 31, 2001 in 1-11299).

(a) 7 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 2009 in 1-11299).

(a) 8 --	Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate dated June 24, 1974 in 70-5399).

(a) 9 --	First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399).

(a) 10 --	Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592).

(a) 11 --	Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate dated July 6, 1984 in 70-6985).

(a) 12 --	Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399).

(a) 13 --	Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 22, 2003, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and Union Bank of California, N.A (10(a)25 to Form 10-K for the year ended December 31, 2003 in 1-11299).

(a) 14 --	First Amendment to Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 2004 (10(a)24 to Form 10-K for the year ended December 31, 2004 in 1-11299).

(a) 15 --	Thirty-sixth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2007, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and The Bank of New York and Douglas J. MacInnes, as trustees (10(a)24 to Form 10-K for the year ended December 31, 2007 in 1-11299).

(a) 16 --	Capital Funds Agreement, dated June 21, 1974, between Entergy Corporation and System Energy (C to Rule 24 Certificate dated June 24, 1974 in 70-5399).

(a) 17 --	First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399).

(a) 18 --	Thirty-fifth Supplementary Capital Funds Agreement and Assignment, dated as of December 22, 2003, among Entergy Corporation, System Energy, and Union Bank of California, N.A (10(a)38 to Form 10-K for the year ended December 31, 2003 in 1-11299).

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(a) 19 --	Thirty-sixth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2007, among Entergy Corporation, System Energy and The Bank of New York and Douglas J. MacInnes, as Trustees (10(a)36 to Form 10-K for the year ended December 31, 2007 in 1-11299).

(a) 20 --	First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, Deposit Guaranty National Bank, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7026).

(a) 21 --	First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7123).

(a) 22 --	First Amendment to Supplementary Capital Funds Agreement and Assignment, dated as of June 1, 1989, by and between Entergy Corporation, System Energy and Chemical Bank (C to Rule 24 Certificate dated June 8, 1989 in 70-7561).

(a) 23 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).

(a) 24 --	Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).

(a) 25 --	Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).

(a) 26 --	Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).

(a) 27 --	Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).

(a) 28 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).

(a) 29 --	Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).

(a) 30 --	Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-3517).

(a) 31 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(a) 32 --	First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).

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(a) 33 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).

(a) 34 --	Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).

(a) 35 --	First Amendment, dated January 1, 1990, to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).

(a) 36 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).

(a) 37 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).

(a) 38 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(a) 39 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299).

(a) 40 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-11299).

(a) 41 --	Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).

(a) 42 --	Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).

(a) 43 --	Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70- 7757).

(a) 44 --	Loan Agreement between Entergy Operations and Entergy Corporation, dated as of September 20, 1990 (B-12(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).

(a) 45 --	Loan Agreement between Entergy Corporation and Entergy Systems and Service, Inc., dated as of December 29, 1992 (A-4(b) to Rule 24 Certificate in 70-7947).

+(a) 46 --	Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a)64 to Form 10-K for the year ended December 31, 2001 in 1-11299).

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+(a) 47 --	Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate dated May 24, 1991 in 70-7831).

+(a) 48 --	Amendment No. 1 to the Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a)71 to Form 10-K for the year ended December 31, 1992 in 1-3517).

+(a) 49 --	2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections On or After January 1, 2007) (Appendix B to Entergy Corporation’s definitive proxy statement for its annual meeting of stockholders held on May 12, 2006 in 1-11299)

*+(a) 50 --	First Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective October 26, 2006.

*+(a) 51 --	Second Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective January 1, 2009.

*+(a) 52 --	Third Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective December 30, 2010.

+(a) 53 --	Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections After February 13, 2003) (10(a) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299).

*+(a) 54 --	First Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2005.

*+(a) 55 --	Second Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective October 26, 2006.

*+(a) 56 --	Third Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009.

*+(a) 57 --	Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009.

*+(a) 58 --	First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010.

*+(a) 59 --	Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009.

*+(a) 60 --	First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries effective December 30, 2010.

+(a) 61 --	Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299).

*+(a) 62 --	Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009.

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*+(a) 63 --	First Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries effective December 30, 2010.

+(a) 64 --	Equity Awards Plan of Entergy Corporation and Subsidiaries, effective as of August 31, 2000 (10(a)77 to Form 10-K for the year ended December 31, 2001 in 1-11299).

+(a) 65 --	Amendment, effective December 7, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(a)78 to Form 10-K for the year ended December 31, 2001 in 1-11299).

+(a) 66 --	Amendment, effective December 10, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended March 31, 2002 in 1-11299).

+(a) 67 --	System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of January 1, 2009 (10(a)77 to Form 10-K for the year ended December 31, 2009 in 1-11299).

+(a) 68--	First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010 (10(a)78 to Form 10-K for the year ended December 31, 2009 in 1-11299).

*+(a) 69 --	Second Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010.

+(a) 70 --	System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective March 8, 2004 (10(e) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 71 --	First Amendment of the System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective December 29, 2004 (10(a)78 to Form 10-K for the year ended December 31, 2004 in 1-11299).

+(a) 72 --	Post-Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)80 to Form 10-K for the year ended December 31, 2001 in 1-11299).

+(a) 73 --	Amendment, effective December 28, 2001, to the Post-Retirement Plan of Entergy Corporation and Subsidiaries (10(a)81 to Form 10-K for the year ended December 31, 2001 in 1-11299).

*+(a) 74 --	Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009.

*+(a) 75 --	First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010.

+(a) 76 --	Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a) to Form 10-Q for the quarter ended June 30, 2008 in 1-11299).

+(a) 77 --	Executive Income Security Plan of Gulf States Utilities Company, as amended effective March 1, 1991 (10(a)86 to Form 10-K for the year ended December 31, 2001 in 1-11299).

*+(a) 78 --	System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009.

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*+(a) 79 --	First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010.

+(a) 80 --	Retention Agreement effective October 27, 2000 between J. Wayne Leonard and Entergy Corporation (10(a)81 to Form 10-K for the year ended December 31, 2000 in 1-11299).

+(a) 81 --	Amendment to Retention Agreement effective March 8, 2004 between J. Wayne Leonard and Entergy Corporation (10(c) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 82 --	Amendment to Retention Agreement effective December 30, 2005 between J. Wayne Leonard and Entergy Corporation (10(a)91 to Form 10-K for the year ended December 31, 2005 in 1-11299).

*+(a) 83 --	Amendment to Retention Agreement effective January 1, 2009 between J. Wayne Leonard and Entergy Corporation.

+(a) 84 --	Amendment to Retention Agreement effective January 1, 2010 between J. Wayne Leonard and Entergy Corporation (10(a)92 to Form 10-K for the year ended December 31, 2009 in 1-11299).

*+(a) 85 --	Amendment to Retention Agreement effective December 30, 2010 between J. Wayne Leonard and Entergy Corporation.

+(a) 86 --	Restricted Unit Agreement between J. Wayne Leonard and Entergy Corporation (10(a)93 to Form 10-K for the year ended December 31, 2009 in 1-11299).

(a) 87 --	Agreement of Limited Partnership of Entergy-Koch, LP among EKLP, LLC, EK Holding I, LLC, EK Holding II, LLC and Koch Energy, Inc. dated January 31, 2001 (10(a)94 to Form 10-K/A for the year ended December 31, 2000 in 1-11299).

+(a) 88 --	Employment Agreement effective April 15, 2003 between Robert D. Sloan and Entergy Services (10(c) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299).

+(a) 89 --	Employment Agreement effective November 24, 2003 between Mark T. Savoff and Entergy Services (10(a)99 to Form 10-K for the year ended December 31, 2003 in 1-11299).

+(a) 90 --	Employment Agreement effective February 9, 1999 between Leo P. Denault and Entergy Services (10(a) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 91 --	Amendment to Employment Agreement effective March 5, 2004 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 92 --	Retention Agreement effective August 3, 2006 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended June 30, 2006 in 1-11299).

*+(a) 93 --	Amendment to Retention Agreement effective January 1, 2009 between Leo P. Denault and Entergy Corporation.

+(a) 94 --	Amendment to Retention Agreement effective January 1, 2010 between Leo P. Denault and Entergy Corporation (10(a)101 to Form 10-K for the year ended December 31, 2009 in 1-11299).

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*+(a) 95 --	Amendment to Retention Agreement effective December 30, 2010 between Leo P. Denault and Entergy Corporation.

+(a) 96 --	Shareholder Approval of Future Severance Agreements Policy, effective March 8, 2004 (10(f) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 97 --	Entergy Corporation Outside Director Stock Program Established under the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Amended and Restated effective January 1, 2009) (10(b) to Form 10-Q for the quarter ended June 30, 2008 in 1-11299).

+(a) 98 --	First Amendment to Entergy Corporation Outside Director Stock Program Established under the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation Subsidiaries (10(a)105 to Form 10-K for the year ended December 31, 2008 in 1-11299).

+(a) 99 --	Rescission Agreement effective July 26, 2007 between Richard J. Smith and Entergy Services, Inc. (10(d) to Form 10-Q for the quarter ended June 30, 2007 in 1-11299).

(a) 100 --	Entergy Nuclear Retention Plan, as amended and restated January 1, 2007 (10(a)107 to Form 10-K for the year ended December 31, 2007 in 1-11299).

+(a) 101 --	Restricted Unit Agreement between Leo P. Denault and Entergy Corporation (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 1-11299).

+(a) 102 --	Retention Agreement effective December 16, 2009 between Richard J. Smith and Entergy Corporation (10(a)112 to Form 10-K for the year ended December 31, 2009 in 1-11299).

+(a) 103 --	Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries as amended and restated effective January 1, 2010 (Annex A to Entergy Corporation’s definitive proxy statement for its annual meeting of stockholders held on May 7, 2010).

*+(a) 104 --	Form of Stock Option Grant Letter, as of January 27, 2011.

*+(a) 105 --	Form of Long Term Incentive Program Performance Unit Grant Letter, as of January 27, 2011.

*+(a) 106 --	Form of Restricted Stock Grant Letter, as of January 27, 2011.

System Energy

(b) 1 through (b) 8 -- See 10(a)8 through 10(a)15 above.

(b) 9 through (b) 15 -- See 10(a)16 through 10(a)22 above.

(b) 16 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).

(b) 17 --	Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337).

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(b) 18 --	Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337).

(b) 19 --	Amended and Restated Installment Sale Agreement, dated as of February 15, 1996, between System Energy and Claiborne County, Mississippi (B-6(a) to Rule 24 Certificate dated March 4, 1996 in 70-8511).

(b) 20 --	Loan Agreement, dated as of October 15, 1998, between System Energy and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated November 12, 1998 in 70-8511).

(b) 21 --	Loan Agreement, dated as of May 15, 1999, between System Energy and Mississippi Business Finance Corporation (B-6(c) to Rule 24 Certificate dated June 8, 1999 in 70-8511).

(b) 22 --	Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

(b) 23 --	Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

(b) 24 --	Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561).

(b) 25 --	Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561).

(b) 26 --	Collateral Trust Indenture, dated as of May 1, 2004, among GG1C Funding Corporation, System Energy, and Deutsche Bank Trust Company Americas, as Trustee (A-3(a) to Rule 24 Certificate dated June 4, 2004 in 70-10182), as supplemented by Supplemental Indenture No. 1 dated May 1, 2004, (A-4(a) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

(b) 27 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337).

(b) 28 --	Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033).

(b) 29 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).

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(b) 30 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).

(b) 31 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).

(b) 32 --	Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate dated March 3, 1989 in 70-7604).

(b) 33 --	System Energy’s Consent, dated January 31, 1995, pursuant to Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(c) to Rule 24 Certificate dated February 13, 1995 in 70-7604).

(b) 34 --	Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).

(b) 35 --	Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).

(b) 36 --	Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).

(b) 37 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).

(b) 38 --	First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).

(b) 39 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).

(b) 40 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).

(b) 41 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(b) 42 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-9067).

(b) 43 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-9067).

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(b) 44 --	Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)43 to Form 10-K for the year ended December 31, 1988 in 1-9067).

(b) 45 --	Amendment, dated January 1, 2004, to Service Agreement with Entergy Services (10(b)57 to Form 10-K for the year ended December 31, 2004 in 1-9067).

(b) 46 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(b)62 to Form 10-K for the year ended December 31, 2009 in 1-9067).

(b) 47 --	Operating Agreement between Entergy Operations and System Energy, dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).

(b) 48 --	Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).

(b) 49 --	Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003, among System Energy Resources, Inc., Union Bank of California, N.A., as administrating bank and funding bank, Keybank National Association, as syndication agent, Banc One Capital Markets, Inc., as documentation agent, and the Banks named therein, as Participating Banks (10(b)63 to Form 10-K for the year ended December 31, 2003 in 1-9067).

(b) 50 --	Amendment to Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003 (10(b)62 to Form 10-K for the year ended December 31, 2004 in 1-9067).

(b) 51 --	First Amendment and Consent, dated as of May 3, 2004, to Letter of Credit and Reimbursement Agreement (10(b)63 to Form 10-K for the year ended December 31, 2004 in 1-9067).

(b) 52 --	Second Amendment and Consent, dated as of December 17, 2004, to Letter of Credit and Reimbursement Agreement (99 to Form 8-K dated December 22, 2004 in 1-9067).

(b) 53 --	Third Amendment and Consent, dated as of May 14, 2009, to Letter of Credit and Reimbursement Agreement (10(b)69 to Form 10-K for the year ended December 31, 2009 in 1-9067).

(b) 54 --	Fourth Amendment and Consent, dated as of April 15, 2010, to Letter of Credit and Reimbursement Agreement (10(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-9067).

Entergy Arkansas

(c) 1 --	Agreement, dated April 23, 1982, among Entergy Arkansas and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(c) 2 --	Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-10764).

(c) 3 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).

(c) 4 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080).

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(c) 5 --	Amendment, dated April 27, 1984, to Service Agreement, with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).

(c) 6 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 to Form 10-K for the year ended December 31, 2002 in 1-10764).

(c) 7 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(c)7 to Form 10-K for the year ended December 31, 2009 in 1-10764).

(c) 8 through (c) 15 -- See 10(a)8 through 10(a)15 above.

(c) 16 --	Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467).

(c) 17 --	Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)2 in 2-41080).

(c) 18 --	Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)3 in 2-41080).

(c) 19 --	Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)4 in 2-41080).

(c) 20 --	Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)5 in 2-41080).

(c) 21 --	Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)6 in 2-41080).

(c) 22 --	Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)7 in 2-41080).

(c) 23 --	Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)8 in 2-41080).

(c) 24 --	Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)9 in 2-43175).

(c) 25 --	Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)10 in 2-60233).

(c) 26 --	Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080).

(c) 27 --	Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)1 in 2-60233).

(c) 28 --	Contract, dated May 28, 1943, Amendment to Contract, dated July 21, 1949, and Supplement to Amendment to Contract, dated December 30, 1949, between Entergy Arkansas and McKamie Gas Cleaning Company; Agreements, dated as of September 30, 1965, between Entergy Arkansas and former stockholders of McKamie Gas Cleaning Company; and Letter Agreement, dated June 22, 1966, by Humble Oil & Refining Company accepted by Entergy Arkansas on June 24, 1966 (5(k)7 in 2-41080).

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(c) 29 --	Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (B-1(b) to Rule 24 Certificate in 70-7571).

(c) 30 --	White Bluff Operating Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-2(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).

(c) 31 --	White Bluff Ownership Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009).

(c) 32 --	Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r)3 in 2-66235).

(c) 33 --	Transmission Agreement, dated August 2, 1977, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)3 in 2-60233).

(c) 34 --	Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and Entergy Arkansas (5(r)4 in 2-60233).

(c) 35 --	Independence Steam Electric Station Operating Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)6 in 2-66235).

(c) 36 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 1-10764).

(c) 37 --	Independence Steam Electric Station Ownership Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)7 in 2-66235).

(c) 38 --	Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)7(a) in 2-66235).

(c) 39 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 1-10764).

(c) 40 --	Owner’s Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 1-10764).

(c) 41 --	Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 1-10764).

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(c) 42 --	Power Coordination, Interchange and Transmission Service Agreement, dated as of July 31, 1979, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)8 in 2-66235).

(c) 43 --	Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and Entergy Arkansas (5(r)9 in 2-66235).

(c) 44 --	Agreement, dated June 21, 1979, between Entergy Arkansas and Reeves E. Ritchie (10(b)90 to Form 10-K for the year ended December 31, 1980 in 1-10764).

(c) 45 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).

(c) 46 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(c) 47 --	First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).

(c) 48 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).

(c) 49 --	Contract For Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated June 30, 1983, among the DOE, System Fuels and Entergy Arkansas (10(b)57 to Form 10-K for the year ended December 31, 1983 in 1-10764).

(c) 50 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).

(c) 51 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).

(c) 52 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).

(c) 53 --	Third Amendment dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).

(c) 54 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(c) 55 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-10764).

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(c) 56 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-10764).

(c) 57 --	Assignment of Coal Supply Agreement, dated December 1, 1987, between System Fuels and Entergy Arkansas (B to Rule 24 letter filing dated November 10, 1987 in 70-5964).

(c) 58 --	Coal Supply Agreement, dated December 22, 1976, between System Fuels and Antelope Coal Company (B-1 in 70-5964), as amended by First Amendment (A to Rule 24 Certificate in 70-5964); Second Amendment (A to Rule 24 letter filing dated December 16, 1983 in 70-5964); and Third Amendment (A to Rule 24 letter filing dated November 10, 1987 in 70-5964).

(c) 59 --	Operating Agreement between Entergy Operations and Entergy Arkansas, dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679).

(c) 60 --	Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).

(c) 61 --	Agreement for Purchase and Sale of Independence Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate dated September 6, 1990 in 70-7684).

(c) 62 --	Agreement for Purchase and Sale of Ritchie Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24 Certificate dated September 6, 1990 in 70-7684).

(c) 63 --	Ritchie Steam Electric Station Unit No. 2 Operating Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-5(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).

(c) 64 --	Ritchie Steam Electric Station Unit No. 2 Ownership Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-6(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684).

(c) 65 --	Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and Entergy Arkansas, dated as of August 28, 1990 (10(c)71 to Form 10-K for the year ended December 31, 1990 in 1-10764).

Entergy Gulf States Louisiana

(d) 1 --	Guaranty Agreement, dated August 1, 1992, between Entergy Gulf States, Inc. and Hibernia National Bank, relating to Pollution Control Revenue Refunding Bonds of the Industrial Development Board of the Parish of Calcasieu, Inc. (Louisiana) (10-1 to Form 10-K for the year ended December 31, 1992 in 1-27031).

(d) 2 --	Guaranty Agreement, dated January 1, 1993, between Entergy Gulf States, Inc. and Hancock Bank of Louisiana, relating to Pollution Control Revenue Refunding Bonds of the Parish of Pointe Coupee (Louisiana) (10-2 to Form 10-K for the year ended December 31, 1992 in 1-27031).

(d) 3 --	Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031).

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(d) 4 --	Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between Entergy Gulf States, Inc., Cajun, and SRG&T; Power Interconnection Agreement with Cajun, dated June 26, 1978, and approved by the REA on August 16, 1979, between Entergy Gulf States, Inc. and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between Entergy Gulf States, Inc. and Cajun (2, 3, and 4, respectively, to Form 8-K dated September 7, 1979 in 1-27031).

(d) 5 --	Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031).

(d) 6 --	Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031).

(d) 7 --	Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031).

(d) 8 --	Agreements between Southern Company and Entergy Gulf States, Inc., dated February 25, 1982, which cover the construction of a 140-mile transmission line to connect the two systems, purchase of power and use of transmission facilities (10-31 to Form 10-K for the year ended December 31, 1981 in 1-27031).

(d) 9 --	Transmission Facilities Agreement between Entergy Gulf States, Inc. and Mississippi Power Company, dated February 28, 1982, and Amendment, dated May 12, 1982 (A-2-c to Form 10-Q for the quarter ended March 31, 1982 in 1-27031) and Amendment, dated December 6, 1983 (10-43 to Form 10-K for the year ended December 31, 1983 in 1-27031).

(d) 10 --	First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031).

+(d) 11 --	Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).

+(d) 12 --	Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031).

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+(d) 13 --	Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031).

+(d) 14 --	Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).

+(d) 15 --	Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031).

(d) 16 --	Nuclear Fuel Lease Agreement between Entergy Gulf States, Inc. and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031).

(d) 17 --	Trust and Investment Management Agreement between Entergy Gulf States, Inc. and Morgan Guaranty and Trust Company of New York (the “Decommissioning Trust Agreement”) with respect to decommissioning funds authorized to be collected by Entergy Gulf States, Inc., dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-27031).

(d) 18 --	Amendment No. 2 dated November 1, 1995 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)31 to Form 10-K for the year ended December 31, 1995 in 1-27031).

(d) 19 --	Amendment No. 3 dated March 5, 1998 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)23 to Form 10-K for the year ended December 31, 2004 in 1-27031).

(d) 20 --	Amendment No. 4 dated December 17, 2003 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)24 to Form 10-K for the year ended December 31, 2004 in 1-27031).

(d) 21 --	Amendment No. 5 dated December 31, 2007 between Entergy Gulf States Louisiana, L.L.C. and Mellon Bank. N.A. to Decommissioning Trust Agreement (10(d)21 to Form 10-K for the year ended December 31, 2007 in 333-148557).

(d) 22 --	Partnership Agreement by and among Conoco Inc., and Entergy Gulf States, Inc., CITGO Petroleum Corporation and Vista Chemical Company, dated April 28, 1988 (10-67 to Form 10-K for the year ended December 31, 1988 in 1-27031).

+(d) 23 --	Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031).

+(d) 24 --	Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031).

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+(d) 25 --	Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031).

(d) 26 --	Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).

(d) 27 --	Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(d) 28 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 0-20371).

(d) 29 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-20371).

(d) 30 --	Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States, Inc. and Parish of Iberville, State of Louisiana (B-3(a) to Rule 24 Certificate dated May 29, 1998 in 70-8721).

(d) 31 --	Amendment No. 1 effective as of October 31, 2007, to Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States, Inc. and Parish of Iberville, State of Louisiana (10(d)29 to Form 10-K for the year ended December 31, 2007 in 333-148557).

(d) 32 --	Operating Agreement dated as of January 1, 2008, between Entergy Operations, Inc. and Entergy Gulf States Louisiana (10(d)39 to Form 10-K for the year ended December 31, 2007 in 333-148557).

(d) 33 --	Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Gulf States Louisiana (10(d)40 to Form 10-K for the year ended December 31, 2007 in 333-148557).

(d) 34 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(d)45 to Form 10-K for the year ended December 31, 2009 in 0-20371).

(d) 35 --	Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 333-148557).

(d) 36 --	Decommissioning Trust Agreement, dated as of December 22, 1997, by and between Cajun Electric Power Cooperative, Inc. and Mellon Bank, N.A. with respect to decommissioning funds authorized to be collected by Cajun Electric Power Cooperative, Inc. and related Settlement Term Sheet (10(d)42 to Form 10-K for the year ended December 31, 2007 in 333-148557).

(d) 37 --	First Amendment to Decommissioning Trust Agreement, dated as of December 23, 2003, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States, Inc., and the Rural Utilities Services of the United States Department of Agriculture (10(d)43 to Form 10-K for the year ended December 31, 2007 in 333-148557).

(d) 38 --	Second Amendment to Decommissioning Trust Agreement, dated December 31, 2007, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States Louisiana, L.L.C., and the Rural Utilities Services of the United States Department of Agriculture (10(d)44 to Form 10-K for the year ended December 31, 2007 in 333-148557).

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(d) 39 --	Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 22, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010).

(d) 40 --	Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010A (4(b) to Form 8-K filed October 12, 2010 in 0-20371).

(d) 41 --	Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010B (4(e) to Form 8-K filed October 12, 2010 in 0-20371).

Entergy Louisiana

(e) 1 --	Agreement, dated April 23, 1982, among Entergy Louisiana and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982, in 1-3517).

(e) 2 --	Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-32718).

(e) 3 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).

(e) 4 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-42523).

(e) 5 --	Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).

(e) 6 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(e)12 to Form 10-K for the year ended December 31, 2002 in 1-8474).

(e) 7 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(e)7 to Form 10-K for the year ended December 31, 2009 in 1-32718).

(e) 8 through (e) 15 -- See 10(a)8 through 10(a)15 above.

(e) 16 --	Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580).

(e) 17 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).

(e) 18 --	Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-8474).

(e) 19 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).

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(e) 20 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).

(e) 21 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).

(e) 22 --	Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and Entergy Louisiana (10(d)33 to Form 10-K for the year ended December 31, 1984 in 1-8474).

(e) 23--	Operating Agreement between Entergy Operations and Entergy Louisiana, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate dated June 15, 1990 in 70-7679).

(e) 24 --	Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757).

(e) 25 --	Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 22, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010).

(e) 26 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-32718).

(e) 27 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-32718).

(e) 28 --	Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Louisiana, LLC relating to Revenue Bonds (Entergy Louisiana, LLC Project) Series 2010 (4(b) to Form 8-K filed October 12, 2010 in 1-32718).

Entergy Mississippi

(f) 1 --	Agreement dated April 23, 1982, among Entergy Mississippi and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(f) 2 --	Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-31508).

(f) 3 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).

(f) 4 --	Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63).

(f) 5 --	Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).

(f) 6 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(f)12 to Form 10-K for the year ended December 31, 2002 in 1-31508).

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(f) 7 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(f)7 to Form 10-K for the year ended December 31, 2009 in 1-31508).

(f) 8 through (f) 15 -- See 10(a)8 through 10(a)15 above.

(f) 16 --	Loan Agreement, dated as of September 1, 2004, between Entergy Mississippi and Mississippi Business Finance Corporation (B-3(a) to Rule 24 Certificate dated October 4, 2004 in 70-10157).

(f) 17 --	Refunding Agreement, dated as of May 1, 1999, between Entergy Mississippi and Independence County, Arkansas (B-6(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719).

(f) 18 --	Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B-3(a) in 70-6337).

(f) 19 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 0-375).

(f) 20 --	Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 0-375).

(f) 21 --	Owners Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi and other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 0-375).

(f) 22 --	Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 0-375).

(f) 23 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).

+(f) 24 --	Post-Retirement Plan (10(d)24 to Form 10-K for the year ended December 31, 1983 in 0-320).

(f) 25 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(f) 26 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).

(f) 27 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).

(f) 28 --	Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399).

(f) 29 --	Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399).

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(f) 30 --	Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399).

(f) 31 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).

(f) 32 --	First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).

(f) 33 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).

(f) 34 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).

(f) 35 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(f) 36 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-31508).

(f) 37 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-31508).

(f) 38 --	Purchase and Sale Agreement by and between Central Mississippi Generating Company, LLC and Entergy Mississippi, Inc., dated as of March 16, 2005 (10(b) to Form 10-Q for the quarter ended March 31, 2005 in 1-31508).

Entergy New Orleans

(g) 1 --	Agreement, dated April 23, 1982, among Entergy New Orleans and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(g) 2 --	Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 0-5807).

(g) 3 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).

(g) 4 --	Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)5 in 2-42523).

(g) 5 --	Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517).

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(g) 6 --	Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(g)12 to Form 10-K for the year ended December 31, 2002 in 0-5807).

(g) 7 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(g)7 to Form 10-K for the year ended December 31, 2009 in 0-5807).

(g) 8 through (g) 15 -- See 10(a)8 through 10(a)15 above.

(g) 16 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).

(g) 17 --	Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517).

(g) 18 --	First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517).

(g) 19 --	Revised Unit Power Sales Agreement (10(ss) in 33-4033).

(g) 20 --	Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, Entergy New Orleans and Regional Transit Authority (2(a) to Form 8-K dated June 24, 1983 in 1-1319).

(g) 21 --	Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987).

(g) 22 --	First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989).

(g) 23 --	Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992).

(g) 24 --	Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).

(g) 25 --	Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(g) 26 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 0-5807).

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Table of Contents

(g) 27 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-5807).

(g) 28 --	Chapter 11 Plan of Reorganization of Entergy New Orleans, Inc., as modified, dated May 2, 2007, confirmed by bankruptcy court order dated May 7, 2007 (2(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).

Entergy Texas

(h) 1 --	Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031).

(h) 2 --	Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and Entergy Gulf States, Inc., as amended (3 to Form 8-K dated August 19, 1980 and A-3-b to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).

(h) 3 --	Lease and Sublease Agreement, dated August 15, 1980, between Statmont and Entergy Gulf States, Inc., as amended (4 to Form 8-K dated August 19, 1980 and A-3-c to Form 10-Q for the quarter ended September 30, 1983 in 1-27031).

(h) 4 --	Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031).

(h) 5 --	Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031).

(h) 6 --	Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031).

(h) 7 --	First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031).

+(h) 8 --	Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).

+(h) 9 --	Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031).

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+(h) 10 --	Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031).

+(h) 11 --	Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551).

+(h) 12 --	Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031).

(h) 13 --	Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and Entergy Gulf States, Inc. related to the leaseback of the Lewis Creek generating station (10-83 to Form 10-K for the year ended December 31, 1988 in 1-27031).

+(h) 14 --	Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031).

+(h) 15 --	Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031).

+(h) 16 --	Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031).

(h) 17 --	Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993).

(h) 18 --	Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996).

(h) 19 --	Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-34360).

(h) 20 --	Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-34360).

(h) 21 --	Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Texas (10(h)25 to Form 10-K for the year ended December 31, 2008 in 3-53134).

(h) 22 --	Amendment, dated June 1, 2009, to Service Agreement with Entergy Services (10(h)27 to Form 10-K for the year ended December 31, 2009 in 1-34360).

E-32

Table of Contents

(12) Statement Re Computation of Ratios

*(a)	Entergy Arkansas’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.

*(b)	Entergy Gulf States Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined.

*(c)	Entergy Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined.

*(d)	Entergy Mississippi’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.

*(e)	Entergy New Orleans’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.

*(f)	Entergy Texas’s Computation of Ratios of Earnings to Fixed Charges, as defined.

*(g)	System Energy’s Computation of Ratios of Earnings to Fixed Charges, as defined.

*(21) Subsidiaries of the Registrants

(23) Consents of Experts and Counsel

*(a)	The consent of Deloitte & Touche LLP is contained herein at page 473.

*(24) Powers of Attorney

(31) Rule 13a-14(a)/15d-14(a) Certifications

*(a)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

*(b)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

*(c)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.

*(d)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.

*(e)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana.

*(f)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana.

*(g)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.

*(h)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.

*(i)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.

*(j)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.

*(k)	Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.

E-33

Table of Contents

*(l)	Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.

*(m)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.

*(n)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.

*(o)	Rule 13a-14(a)/15d-14(a) Certification for System Energy.

*(p)	Rule 13a-14(a)/15d-14(a) Certification for System Energy.

(32) Section 1350 Certifications

*(a)	Section 1350 Certification for Entergy Corporation.

*(b)	Section 1350 Certification for Entergy Corporation.

*(c)	Section 1350 Certification for Entergy Arkansas.

*(d)	Section 1350 Certification for Entergy Arkansas.

*(e)	Section 1350 Certification for Entergy Gulf States Louisiana.

*(f)	Section 1350 Certification for Entergy Gulf States Louisiana.

*(g)	Section 1350 Certification for Entergy Louisiana.

*(h)	Section 1350 Certification for Entergy Louisiana.

*(i)	Section 1350 Certification for Entergy Mississippi.

*(j)	Section 1350 Certification for Entergy Mississippi.

*(k)	Section 1350 Certification for Entergy New Orleans.

*(l)	Section 1350 Certification for Entergy New Orleans.

*(m)	Section 1350 Certification for Entergy Texas.

*(n)	Section 1350 Certification for Entergy Texas.

*(o)	Section 1350 Certification for System Energy.

*(p)	Section 1350 Certification for System Energy.

(101) XBRL Documents

Entergy Corporation

*INS -	XBRL Instance Document.

*SCH -	XBRL Taxonomy Extension Schema Document.

E-34

Table of Contents

*CAL -	XBRL Taxonomy Extension Calculation Linkbase Document.

*DEF -	XBRL Taxonomy Extension Definition Linkbase Document.

*LAB -	XBRL Taxonomy Extension Label Linkbase Document.

*PRE -	XBRL Taxonomy Extension Presentation Linkbase Document.

_________________

* Filed herewith.

+ Management contracts or compensatory plans or arrangements.

E-35

(Mark One)

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Fiscal Year Ended December 31, 2010
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________

Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.	Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.
1-11299	ENTERGY CORPORATION (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000 72-1229752	1-31508	ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 64-0205830


1-10764	ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000 71-0005900	0-05807	ENTERGY NEW ORLEANS, INC. (a Louisiana corporation) 1600 Perdido Street New Orleans, Louisiana 70112 Telephone (504) 670-3700 72-0273040


0-20371	ENTERGY GULF STATES LOUISIANA, L.L.C. (a Louisiana limited liability company) 446 North Boulevard Baton Rouge, Louisiana 70802 Telephone (800) 368-3749 74-0662730	1-34360	ENTERGY TEXAS, INC. (a Texas corporation) 350 Pine Street Beaumont, Texas 77701 Telephone (409) 981-2000 61-1435798


1-32718	ENTERGY LOUISIANA, LLC (a Texas limited liability company) 446 North Boulevard Baton Rouge, Louisiana 70802 Telephone (800) 368-3749 75-3206126	1-09067	SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 72-0752777

Registrant	Title of Class	Name of Each Exchange on Which Registered

Entergy Corporation	Common Stock, $0.01 Par Value – 179,037,924 shares outstanding at January 31, 2011	New York Stock Exchange, Inc. Chicago Stock Exchange, Inc.

Entergy Arkansas, Inc.	Mortgage Bonds, 5.75% Series due November 2040	New York Stock Exchange, Inc.

Entergy Louisiana, LLC	Mortgage Bonds, 6.0% Series due March 2040	New York Stock Exchange, Inc.
	Mortgage Bonds, 5.875% Series due June 2041	New York Stock Exchange, Inc.

Entergy Mississippi, Inc.	Mortgage Bonds, 6.0% Series due November 2032	New York Stock Exchange, Inc.
	Mortgage Bonds, 6.20% Series due April 2040	New York Stock Exchange, Inc.

Entergy Texas, Inc.	Mortgage Bonds, 7.875% Series due June 2039	New York Stock Exchange, Inc.

	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company

Entergy Corporation	Ö
Entergy Arkansas, Inc.			Ö
Entergy Gulf States Louisiana, L.L.C.			Ö
Entergy Louisiana, LLC			Ö
Entergy Mississippi, Inc.			Ö
Entergy New Orleans, Inc.			Ö
Entergy Texas, Inc.			Ö
System Energy Resources, Inc.			Ö

Report of Independent Registered Public Accounting Firm		363
Consolidated Income Statements For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	364
Consolidated Statements of Cash Flows For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	365
Consolidated Balance Sheets, December 31, 2010 and 2009	Part II. Item 8.	366
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	368
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	369
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	370
Results of Operations		370
Liquidity and Capital Resources		370
Nuclear Matters		374
Environmental Risks		374
Critical Accounting Estimates		374
New Accounting Pronouncements		375
Report of Independent Registered Public Accounting Firm		377
Income Statements For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	378
Statements of Cash Flows For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	379
Balance Sheets, December 31, 2010 and 2009	Part II. Item 8.	380
Statements of Changes in Common Equity for the Years Ended December 31, 2009, and 20082010, 2010, 2009, and 2008	Part II. Item 8.	382
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	383
Properties	Part I. Item 2.	384
Legal Proceedings	Part I. Item 3.	384
Executive Officers of Entergy Corporation	Part I and Part III. Item 10.	384
Market for Registrants’ Common Equity and Related Stockholder Matters	Part II. Item 5.	386
Selected Financial Data	Part II. Item 6.	387
Management’s Discussion and Analysis of Financial Condition and Results of Operations	Part II. Item 7.	387
Quantitative and Qualitative Disclosures About Market Risk	Part II. Item 7A.	387
Financial Statements and Supplementary Data	Part II. Item 8.	388
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	Part II. Item 9.	388
Controls and Procedures	Part II. Item 9A.	388
Attestation Report of Registered Public Accounting Firm	Part II. Item 9A.	390
Directors and Executive Officers of the Registrants	Part III. Item 10.	398
Executive Compensation	Part III. Item 11.	403
Security Ownership of Certain Beneficial Owners and Management	Part III. Item 12.	457
Certain Relationships and Related Transactions and Director Independence	Part III. Item 13.	460
Principal Accountant Fees and Services	Part III. Item 14.	461
Exhibits and Financial Statement Schedules	Part IV. Item 15.	464
Signatures		465
Consents of Independent Registered Public Accounting Firm		473
Report of Independent Registered Public Accounting Firm		474
Index to Financial Statement Schedules		S-1
Exhibit Index		E-1

	SEC Form 10-K Reference Number	Page Number

Forward-looking information		vi
Definitions		ix
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	1
Results of Operations		2
Liquidity and Capital Resources		12
Rate, Cost-recovery, and Other Regulation		23
Market and Credit Risk Sensitive Instruments		29
Critical Accounting Estimates		31
New Accounting Pronouncements		38
Report of Management		39
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	40
Report of Independent Registered Public Accounting Firm		41
Consolidated Income Statements For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	43
Consolidated Statements of Cash Flows For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	44
Consolidated Balance Sheets, December 31, 2010 and 2009	Part II. Item 8.	46
Consolidated Statements of Changes in Equity and Comprehensive Income for the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	48
Notes to Financial Statements	Part II. Item 8.	49
Entergy’s Business	Part I. Item 1.
Strategy		185
Utility	Part I. Item 1.	185
Customers		186
Electric Energy Sales		186
Retail Rate Regulation		187
Property and Other Generation Resources		192
Fuel Supply		195
Federal Regulation of the Utility		198
Service Companies		201
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas		201
Earnings Ratios of Registrant Subsidiaries		202
Entergy Wholesale Commodities	Part I. Item 1.	203
Property		203
Energy and Capacity Sales		206
Fuel Supply		207
Other Business Activities		207
Entergy-Koch	Part I. Item 1.	208
Regulation of Entergy’s Business	Part I. Item 1.	208
Energy Policy Act of 2005		208
Federal Power Act		209
State Regulation		209
Regulation of the Nuclear Power Industry		211
Environmental Regulation		213
Litigation		225
Employees		227

Availability of SEC filings and other information on Entergy’s website		228
Risk Factors	Part I. Item 1A.	229
Unresolved Staff Comments	Part I. Item 1B.	None
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	249
Results of Operations		249
Liquidity and Capital Resources		252
State and Local Rate Regulation		257
Federal Regulation		258
Nuclear Matters		258
Environmental Risks		259
Critical Accounting Estimates		259
New Accounting Pronouncements		261
Report of Independent Registered Public Accounting Firm		263
Consolidated Income Statements For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	264
Consolidated Statements of Cash Flows For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	265
Consolidated Balance Sheets, December 31, 2010 and 2009	Part II. Item 8.	266
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	268
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	269
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis	Part II. Item 7.	270
Results of Operations		270
Liquidity and Capital Resources		273
State and Local Rate Regulation		279
Industrial and Commercial Customers		281
Federal Regulation		281
Nuclear Matters		281
Environmental Risks		282
Critical Accounting Estimates		282
New Accounting Pronouncements		283
Report of Independent Registered Public Accounting Firm		285
Income Statements For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	286
Statements of Cash Flows For the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	287
Balance Sheets, December 31, 2010 and 2009	Part II. Item 8.	288
Statements of Changes in Equity and Comprehensive Income for the Years Ended December 31, 2010, 2009, and 2008	Part II. Item 8.	290
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	291
Entergy Louisiana, LLC
Management’s Financial Discussion and Analysis	Part II. Item 7.	292
Results of Operations		292
Liquidity and Capital Resources		295
State and Local Rate Regulation		303
Industrial and Commercial Customers		304
Federal Regulation		304
Nuclear Matters		304
Environmental Risks		305
Critical Accounting Estimates		305
New Accounting Pronouncements		306
Report of Independent Registered Public Accounting Firm		307

Abbreviation or Acronym	Term

AEEC	Arkansas Electric Energy Consumers
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
ANO 1 and 2	Units 1 and 2 of Arkansas Nuclear One (nuclear), owned by Entergy Arkansas
APSC	Arkansas Public Service Commission
Board	Board of Directors of Entergy Corporation
Cajun	Cajun Electric Power Cooperative, Inc.
capacity factor	Actual plant output divided by maximum potential plant output for the period
City Council or Council	Council of the City of New Orleans, Louisiana
DOE	United States Department of Energy
D. C. Circuit	U.S. Court of Appeals for the District of Columbia
Entergy	Entergy Corporation and its direct and indirect subsidiaries
Entergy Corporation	Entergy Corporation, a Delaware corporation
Entergy Gulf States, Inc.	Predecessor company for financial reporting purposes to Entergy Gulf States Louisiana that included the assets and business operations of both Entergy Gulf States Louisiana and Entergy Texas
Entergy Gulf States Louisiana	Entergy Gulf States Louisiana, L.L.C., a company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. and the successor company to Entergy Gulf States, Inc. for financial reporting purposes. The term is also used to refer to the Louisiana jurisdictional business of Entergy Gulf States, Inc., as the context requires.
Entergy-Koch	A joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc. Entergy-Koch’s pipeline and trading businesses were sold in 2004.
Entergy Texas	Entergy Texas, Inc., a company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires.
Entergy Wholesale Commodities	Entergy’s non-utility business segment primarily comprised of the ownership and operation of six nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by those plants to wholesale customers
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
firm LD	Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, the defaulting party must compensate the other party as specified in the contract
FitzPatrick	James A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Grand Gulf	Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy
GWh	Gigawatt-hour(s), which equals one million kilowatt-hours
Independence	Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power
Indian Point 2	Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment

Abbreviation or Acronym	Term

System Fuels	System Fuels, Inc.
TWh	Terawatt-hour(s), which equals one billion kilowatt-hours
unit-contingent	Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to the buyer for any damages
Unit Power Sales Agreement	Agreement, dated as of June 10, 1982, as amended and approved by FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy’s share of Grand Gulf
Utility	Entergy’s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution
Utility operating companies	Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Vermont Yankee	Vermont Yankee Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Waterford 3	Unit No. 3 (nuclear) of the Waterford Steam Electric Station, 100% owned or leased by Entergy Louisiana
weather-adjusted usage	Electric usage excluding the effects of deviations from normal weather
White Bluff	White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas

	% of Revenue			% of Net Income			% of Total Assets
Segment	2010	2009	2008	2010	2009	2008	2010	2009	2008

Utility	78	75	79	65	57	49	80	80	79
Entergy Wholesale Commodities	22	25	21	39	51	64	26	30	25
Parent & Other	-	-	-	(4)	(8)	(13)	(6)	(10)	(4)

	2010	2009

Net MW in operation at December 31	4,998	4,998
Average realized revenue per MWh	$59.16	$61.07
GWh billed	39,655	40,981
Capacity factor	90%	93%
Refueling Outage Days:
FitzPatrick	35	-
Indian Point 2	33	-
Indian Point 3	-	36
Palisades	26	41
Pilgrim	-	31
Vermont Yankee	29	-

Long-term debt maturities and estimated interest payments	2011	2012	2013	2014-2015	after 2015
	(In Millions)

Utility	$653	$677	$1,205	$1,354	$10,554
Entergy Wholesale Commodities	34	31	20	43	46
Parent and Other	143	1,683	43	630	559
Total	$830	$2,391	$1,268	$2,027	$11,159

Contractual Obligations	2011	2012-2013	2014-2015	after 2015	Total
	(In Millions)

Long-term debt (1)	$830	$3,659	$2,027	$11,159	$17,675
Capital lease payments (2)	$6	$13	$9	$44	$72
Operating leases (2)	$88	$146	$124	$188	$546
Purchase obligations (3)	$1,772	$3,114	$2,663	$5,061	$12,610

(1)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(2)	Lease obligations are discussed in Note 10 to the financial statements.
(3)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations.

(1)	A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.
(2)	The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy most of the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below PPA prices, which has not happened thus far.
(3)	Average revenue under contract may fluctuate due to positive or negative basis differences, option premiums, costs to convert firm LD to unit-contingent, and other risk management costs. Also, average revenue under contract excludes payments owed under the value sharing agreement with NYPA.
(4)	Assumes license renewal for plants whose current licenses expire within five years. License renewal applications are in process for four units, as follows (with current license expirations in parentheses): Vermont Yankee (March 2012), Pilgrim (June 2012), Indian Point 2 (September 2013), and Indian Point 3 (December 2015).

Actuarial Assumption	Change in Assumption	Impact on 2010 Qualified Pension Cost	Impact on Qualified Projected Benefit Obligation
	Increase/(Decrease)

Discount rate	(0.25%)	$13,682	$131,414
Rate of return on plan assets	(0.25%)	$7,634	-
Rate of increase in compensation	0.25%	$6,367	$30,374

J. WAYNE LEONARD Chairman of the Board and Chief Executive Officer of Entergy Corporation	LEO P. DENAULT Executive Vice President and Chief Financial Officer of Entergy Corporation
HUGH T. MCDONALD Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc.	WILLIAM M. MOHL Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc.	CHARLES L. RICE, JR. President and Chief Executive Officer of Entergy New Orleans, Inc.
JOSEPH F. DOMINO Chairman of the Board, President, and Chief Executive Officer of Entergy Texas, Inc.	JOHN T. HERRON Chairman, President, and Chief Executive Officer of System Energy Resources, Inc.
THEODORE H. BUNTING, JR. Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc.	WANDA C. CURRY Vice President and Chief Financial Officer of System Energy Resources, Inc.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2010			2009			2008
	(In Thousands, Except Share Data)

OPERATING REVENUES
Electric	$	8,740,637		$	7,880,016		$	10,073,160
Natural gas		197,658			172,213			241,856
Competitive businesses		2,549,282			2,693,421			2,778,740
TOTAL		11,487,577			10,745,650			13,093,756

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale		2,518,582			2,309,831			3,577,764
Purchased power		1,659,416			1,395,203			2,491,200
Nuclear refueling outage expenses		256,123			241,310			221,759
Other operation and maintenance		2,969,402			2,750,810			2,742,762
Decommissioning		211,736			199,063			189,409
Taxes other than income taxes		534,299			503,859			496,952
Depreciation and amortization		1,069,894			1,082,775			1,030,860
Other regulatory charges (credits) - net		44,921			(21,727	)		59,883
TOTAL		9,264,373			8,461,124			10,810,589

Gain on sale of business		44,173			-			-

OPERATING INCOME		2,267,377			2,284,526			2,283,167

OTHER INCOME
Allowance for equity funds used during construction		59,381			59,545			44,523
Interest and investment income		185,455			236,628			197,872
Other than temporary impairment losses		(1,378	)		(86,069	)		(49,656	)
Miscellaneous - net		(48,124	)		(40,396	)		(23,452	)
TOTAL		195,334			169,708			169,287

INTEREST EXPENSE
Interest expense		610,146			603,679			634,188
Allowance for borrowed funds used during construction		(34,979	)		(33,235	)		(25,267	)
TOTAL		575,167			570,444			608,921

INCOME BEFORE INCOME TAXES		1,887,544			1,883,790			1,843,533

Income taxes		617,239			632,740			602,998

CONSOLIDATED NET INCOME		1,270,305			1,251,050			1,240,535

Preferred dividend requirements of subsidiaries		20,063			19,958			19,969

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	1,250,242		$	1,231,092		$	1,220,566


Earnings per average common share:
Basic	$	6.72		$	6.39		$	6.39
Diluted	$	6.66		$	6.30		$	6.20
Dividends declared per common share	$	3.24		$	3.00		$	3.00

Basic average number of common shares outstanding		186,010,452			192,772,032			190,925,613
Diluted average number of common shares outstanding		187,814,235			195,838,068			201,011,588

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2010			2009			2008
	(In Thousands)

OPERATING ACTIVITIES
Consolidated net income	$	1,270,305		$	1,251,050		$	1,240,535
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		1,705,331			1,458,861			1,391,689
Deferred income taxes, investment tax credits, and non-current taxes accrued		718,987			864,684			333,948
Gain on sale of business		(44,173	)		-			-
Changes in working capital:
Receivables		(99,640	)		116,444			78,653
Fuel inventory		(10,665	)		19,291			(7,561	)
Accounts payable		216,635			(14,251	)		(23,225	)
Prepaid taxes and taxes accrued		(116,988	)		(260,029	)		122,134
Interest accrued		17,651			4,974			(652	)
Deferred fuel		8,909			72,314			(38,500	)
Other working capital accounts		(160,326	)		(43,391	)		(119,296	)
Changes in provisions for estimated losses		265,284			(12,030	)		12,462
Changes in other regulatory assets		339,408			(415,157	)		(324,211	)
Changes in pensions and other postretirement liabilities		(80,844	)		71,789			828,160
Other		(103,793	)		(181,391	)		(169,808	)
Net cash flow provided by operating activities		3,926,081			2,933,158			3,324,328

INVESTING ACTIVITIES
Construction/capital expenditures		(1,974,286	)		(1,931,245	)		(2,212,255	)
Allowance for equity funds used during construction		59,381			59,545			44,523
Nuclear fuel purchases		(407,711	)		(525,474	)		(423,951	)
Proceeds from sale/leaseback of nuclear fuel		-			284,997			297,097
Proceeds from sale of assets and businesses		228,171			39,554			30,725
Payment for purchase of plant		-			-			(266,823	)
Insurance proceeds received for property damages		7,894			53,760			130,114
Changes in transition charge account		(29,945	)		(1,036	)		7,211
NYPA value sharing payment		(72,000	)		(72,000	)		(72,000	)
Payments to storm reserve escrow account		(296,614	)		(6,802	)		(248,863	)
Receipts from storm reserve escrow account		9,925			-			249,461
Decrease (increase) in other investments		24,956			100,956			(73,431	)
Proceeds from nuclear decommissioning trust fund sales		2,606,383			2,570,523			1,652,277
Investment in nuclear decommissioning trust funds		(2,730,377	)		(2,667,172	)		(1,704,181	)
Net cash flow used in investing activities		(2,574,223	)		(2,094,394	)		(2,590,096	)

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2010			2009
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$	76,290		$	85,861
Temporary cash investments		1,218,182			1,623,690
Total cash and cash equivalents		1,294,472			1,709,551
Securitization recovery trust account		43,044			13,098
Accounts receivable:
Customer		602,796			553,692
Allowance for doubtful accounts		(31,777	)		(27,631	)
Other		161,662			152,303
Accrued unbilled revenues		302,901			302,463
Total accounts receivable		1,035,582			980,827
Deferred fuel costs		64,659			126,798
Accumulated deferred income taxes		8,472			-
Fuel inventory - at average cost		207,520			196,855
Materials and supplies - at average cost		866,908			825,702
Deferred nuclear refueling outage costs		218,423			225,290
System agreement cost equalization		52,160			70,000
Prepaid taxes		301,807			184,819
Prepayments and other		246,036			201,221
TOTAL		4,339,083			4,534,161

OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		40,697			39,580
Decommissioning trust funds		3,595,716			3,211,183
Non-utility property - at cost (less accumulated depreciation)		257,847			247,664
Other		405,946			120,273
TOTAL		4,300,206			3,618,700

PROPERTY, PLANT AND EQUIPMENT
Electric		37,153,061			36,343,772
Property under capital lease		800,078			783,096
Natural gas		330,608			314,256
Construction work in progress		1,661,560			1,547,319
Nuclear fuel under capital lease		-			527,521
Nuclear fuel		1,377,962			739,827
TOTAL PROPERTY, PLANT AND EQUIPMENT		41,323,269			40,255,791
Less - accumulated depreciation and amortization		17,474,914			16,866,389
PROPERTY, PLANT AND EQUIPMENT - NET		23,848,355			23,389,402

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		845,725			816,856
Other regulatory assets (includes securitization property of $882,346 as of December 31, 2010)		3,838,237			3,647,154
Deferred fuel costs		172,202			172,202
Goodwill		377,172			377,172
Accumulated deferred income taxes		54,523			-
Other		909,773			1,006,306
TOTAL		6,197,632			6,019,690

TOTAL ASSETS	$	38,685,276		$	37,561,953

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2010			2009
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$	299,548		$	711,957
Notes payable and commercial paper		154,135			30,031
Accounts payable		1,181,099			998,228
Customer deposits		335,058			323,342
Accumulated deferred income taxes		49,307			48,584
Interest accrued		217,685			192,283
Deferred fuel costs		166,409			219,639
Obligations under capital leases		3,388			212,496
Pension and other postretirement liabilities		39,862			55,031
System agreement cost equalization		52,160			187,204
Other		277,598			215,202
TOTAL		2,776,249			3,193,997

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		8,573,646			7,662,798
Accumulated deferred investment tax credits		292,330			308,395
Obligations under capital leases		42,078			354,233
Other regulatory liabilities		539,026			378,862
Decommissioning and asset retirement cost liabilities		3,148,479			2,939,539
Accumulated provisions		395,250			141,315
Pension and other postretirement liabilities		2,175,364			2,241,039
Long-term debt (includes securitization bonds of $931,131 as of December 31, 2010)		11,317,157			10,705,738
Other		618,559			711,334
TOTAL		27,101,889			25,443,253

Commitments and Contingencies

Subsidiaries' preferred stock without sinking fund		216,738			217,343

EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2010 and in 2009		2,548			2,548
Paid-in capital		5,367,474			5,370,042
Retained earnings		8,689,401			8,043,122
Accumulated other comprehensive loss		(38,212	)		(75,185	)
Less - treasury stock, at cost (76,006,920 shares in 2010 and
65,634,580 shares in 2009)		5,524,811			4,727,167
Total common shareholders' equity		8,496,400			8,613,360
Subsidiaries' preferred stock without sinking fund		94,000			94,000
TOTAL		8,590,400			8,707,360

TOTAL LIABILITIES AND EQUITY	$	38,685,276		$	37,561,953

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2010, 2009, and 2008

				Common Shareholders’ Equity
	Subsidiaries’ Preferred Stock			Common Stock		Treasury Stock			Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(In Thousands)

Balance at December 31, 2007	$	94,000		$	2,482	$	(3,734,865	)	$	4,850,769		$	6,735,965		$	8,320		$	7,956,671

Consolidated net income (a)		19,969			-		-			-			1,220,566			-			1,240,535
Other comprehensive income:
Cash flow hedges net unrealized gain (net of tax expense of $78,837)		-			-		-			-			-			133,370			133,370
Pension and other postretirement liabilities (net of tax benefit of $68,076)		-			-		-			-			-			(125,087	)		(125,087	)
Net unrealized investment losses (net of tax benefit of $108,049)		-			-		-			-			-			(126,013	)		(126,013	)
Foreign currency translation (net of tax benefit of $1,770)		-			-		-			-			-			(3,288	)		(3,288	)
Total comprehensive income																			1,119,517

Common stock repurchases		-			-		(512,351	)		-			-			-			(512,351	)
Common stock issuances related to stock plans		-			-		72,002			18,534			-			-			90,536
Common stock dividends declared		-			-		-			-			(573,924	)		-			(573,924	)
Preferred dividend requirements of subsidiaries (a)		(19,969	)		-		-			-			-			-			(19,969	)
Capital stock and other expenses		-			-		-			-			112			-			112

Balance at December 31, 2008	$	94,000		$	2,482	$	(4,175,214	)	$	4,869,303		$	7,382,719		$	(112,698	)	$	8,060,592


Consolidated net income (a)		19,958			-		-			-			1,231,092			-			1,251,050
Other comprehensive income:
Cash flow hedges net unrealized loss (net of tax expense of $333)		-			-		-			-			-			(2,887	)		(2,887	)
Pension and other postretirement liabilities (net of tax benefit of $34,415)		-			-		-			-			-			(35,707	)		(35,707	)
Net unrealized investment gains (net of tax expense of $102,845)		-			-		-			-			-			82,929			82,929
Foreign currency translation (net of tax benefit of $246)		-			-		-			-			-			(457	)		(457	)
Total comprehensive income																			1,294,928

Common stock repurchases		-			-		(613,125	)		-			-			-			(613,125	)
Common stock issuances in settlement of equity unit purchase contracts		-			66		-			499,934			-			-			500,000
Common stock issuances related to stock plans		-			-		61,172			805			-			-			61,977
Common stock dividends declared		-			-		-			-			(576,913	)		-			(576,913	)
Preferred dividend requirements of subsidiaries (a)		(19,958	)		-		-			-			-			-			(19,958	)
Capital stock and other expenses		-			-		-			-			(141	)		-			(141	)
Adjustment for implementation of new accounting pronouncement		-			-		-			-			6,365			(6,365	)		-

Balance at December 31, 2009	$	94,000		$	2,548	$	(4,727,167	)	$	5,370,042		$	8,043,122		$	(75,185	)		8,707,360


Consolidated net income (a)		20,063			-		-			-			1,250,242			-			1,270,305
Other comprehensive income:
Cash flow hedges net unrealized loss (net of tax benefit of $7,088)		-			-		-			-			-			(11,685	)		(11,685	)
Pension and other postretirement liabilities (net of tax benefit of $14,387)		-			-		-			-			-			(8,527	)		(8,527	)
Net unrealized investment gains (net of tax expense of $51,130)		-			-		-			-			-			57,523			57,523
Foreign currency translation (net of tax benefit of $182)		-			-		-			-			-			(338	)		(338	)
Total comprehensive income																			1,307,278

Common stock repurchases		-			-		(878,576	)		-			-			-			(878,576	)
Common stock issuances related to stock plans		-			-		80,932			(2,568	)		-			-			78,364
Common stock dividends declared		-			-		-			-			(603,963	)		-			(603,963	)
Preferred dividend requirements of subsidiaries (a)		(20,063	)		-		-			-			-			-			(20,063	)

Balance at December 31, 2010	$	94,000		$	2,548	$	(5,524,811	)	$	5,367,474		$	8,689,401		$	(38,212	)	$	8,590,400

See Notes to Financial Statements.

(a) Consolidated net income and preferred dividend requirements of subsidiaries for 2010, 2009, and 2008 include $13.3 million of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity.

			Entergy
	Entergy		Gulf States	Entergy	Entergy	Entergy	Entergy	System
2010	Arkansas		Louisiana	Louisiana	Mississippi	New Orleans	Texas	Energy
	(In Thousands)
Current:
Federal	$114,821	$196,230		$73,174	$12,812	($114,441)	($10,607)	($4,102)
State	(9,200)	481		(4,324)	5,822	1,412	1,060	3,328
Total	105,621	196,711		68,850	18,634	(113,029)	(9,547)	(774)
Deferred and non-current -- net	10,328	(117,426)		918	31,415	129,880	53,539	60,305
Investment tax credit
adjustments -- net	(3,005)	(3,407)		(3,222)	(985)	(324)	(1,609)	(3,482)
Income taxes	$112,944	$75,878		$66,546	$49,064	$16,527	$42,383	$56,049

Carryover Description	Carryover Amount	Year(s) of expiration

Federal net operating losses	$10 billion	2023-2029
State net operating losses	$7.5 billion	2011-2030
Federal capital losses	$60.7 million	2014
State capital losses	$855 million	2011-2015
Federal minimum tax credits	$29 million	never
Other federal and state credits	$70 million	2011-2030

	December 31, 2010	December 31, 2009	December 31, 2008


Entergy Arkansas	$0.2	$1.2	$1.2
Entergy Gulf States Louisiana	$129.6	$69.8	$75.2
Entergy Louisiana	$286.7	$192.7	$210.4
Entergy Mississippi	$5.3	$3.3	$2.5
Entergy New Orleans	-	$0.3	$0.7
Entergy Texas	$6.0	$1.2	$0.6
System Energy	$12.1	$8.7	$3.9

	Accumulated deferred income taxes and taxes accrued	Regulatory asset for income taxes - net	Regulatory liability for income taxes - net	Other regulatory liabilities
	(In Millions)

Entergy	$240	$197	$-	($43)
Entergy Arkansas	$57	$57	$-	$-
Entergy Gulf States Louisiana	($67)	($67)	$-	$-
Entergy Louisiana	$107	$107	$-	$-
Entergy Mississippi	$25	$25	$-	$-
Entergy New Orleans	$58	$-	($15)	($43)
Entergy Texas	$24	$24	$-	$-
System Energy	$37	$37	$-	$-

	Qualified Pension		Postretirement
Actual Asset Allocation	2010	2009	2010		2009
			Non- Taxable	Taxable	Non- Taxable	Taxable
Domestic Equity Securities	44%	46%	39%	39%	40%	36%
International Equity Securities	20%	21%	18%	0%	19%	0%
Fixed Income Securities	35%	32%	43%	60%	41%	63%
Other	1%	1%	0%	1%	0%	1%

(a)	In 2010, there were two common collective trusts holding investments in accordance with stated objectives. The investment strategy of the both trusts was to capture the growth potential of equity markets by replicating the performance of a specified index. Net asset value per share of the common collective trusts estimated fair value.
(b)	In 2009, there were two common collective trusts holding investments in accordance with stated objectives. The investment strategy of the first trust was to capture the growth potential of equity markets by replicating the performance of a specified index. Fair value for this trust was estimated at net asset value per share. The other common collective trust was invested in short-term fixed income securities and other securities with debt-like characteristics and a high degree of liquidity. This common collective trust fund used the amortization cost method of valuation pursuant to Rule 2a7 of the Investment Company Act of 1940, which allowed it to maintain a stable net asset value of $1.00 per share.
(c)	In 2009 and 2010, the registered investment companies held investments in domestic and international bond markets and estimated fair value using net asset value per share.

	Number of Options	Weighted- Average Exercise Price	Aggregate Intrinsic Value	Weighted- Average Contractual Life

Options outstanding as of January 1, 2010	11,321,071	$69.64

Options granted	1,407,900	$77.10
Options exercised	(1,113,411)	$45.63
Options forfeited/expired	(389,835)	$84.35
Options outstanding as of December 31, 2010	11,225,725	$72.45	$-	4.1 years

Options exercisable as of December 31, 2010	8,955,247	$69.67	$10 million	4.2 years
Weighted-average grant-date fair value of options granted during 2010	$13.18

	Options Outstanding			Options Exercisable
Range of Exercise Prices	As of 12/31/2010	Weighted-Avg. Remaining Contractual Life-Yrs.	Weighted- Avg. Exercise Price	Number Exercisable as of 12/31/2010	Weighted- Avg. Exercise Price

$37 - $50.99	2,472,520	1.3	$42.12	2,472,520	$42.12
$51 - $64.99	984,055	3.2	$58.58	984,055	$58.58
$65 - $78.99	4,616,768	4.1	$73.10	2,797,769	$70.40
$79 - $91.99	1,650,516	6.1	$91.81	1,650,516	$91.81
$92 - $108.20	1,501,866	7.1	$108.20	1,050,387	$108.20
$37 - $108.20	11,225,725	4.1	$72.45	8,955,247	$69.67

2010	Utility	Entergy Wholesale Commodities*	All Other	Eliminations	Consolidated
	(In Thousands)

Operating revenues	$8,941,332	$2,566,156	$7,442	($27,353)	$11,487,577
Deprec., amort. & decomm.	$1,006,385	$270,658	$4,587	$-	$1,281,630
Interest and investment income	$182,493	$171,158	$44,757	($212,953)	$185,455
Interest expense	$493,241	$71,817	$129,505	($119,396)	$575,167
Income taxes (benefits)	$454,227	$268,649	($105,637)	$-	$617,239
Consolidated net income	$829,719	$489,422	$44,721	($93,557)	$1,270,305
Total assets	$31,080,240	$10,102,817	($714,968)	($1,782,813)	$38,685,276
Investment in affiliates - at equity	$199	$59,456	($18,958)	$-	$40,697
Cash paid for long-lived asset additions	$1,766,609	$687,313	$75	$-	$2,453,997

Type of Risk		Affected Businesses

Power price risk		Utility, Entergy Wholesale Commodities
Fuel price risk		Utility, Entergy Wholesale Commodities
Foreign currency exchange rate risk		Utility, Entergy Wholesale Commodities
Equity price and interest rate risk - investments		Utility, Entergy Wholesale Commodities

Instrument	Balance Sheet Location	Fair Value (a)	Offset (a)	Business

Derivatives designated as hedging instruments

Assets:
Electricity futures, forwards, swaps, and options	Prepayments and other (current portion)	$160 million	($7) million	Entergy Wholesale Commodities
Electricity futures, forwards, swaps, and options	Other deferred debits and other assets (non-current portion)	$82 million	($29) million	Entergy Wholesale Commodities

Liabilities:
Electricity futures, forwards, swaps, and options	Other current liabilities (current portion)	$5 million	($5) million	Entergy Wholesale Commodities
Electricity futures, forwards, swaps, and options	Other non-current liabilities (non-current portion)	$47 million	($30) million	Entergy Wholesale Commodities

Derivatives not designated as hedging instruments

Assets:
Electricity futures, forwards, swaps, and options	Prepayments and other (current portion)	$2 million	($-)	Entergy Wholesale Commodities
Electricity futures, forwards, swaps, and options	Other deferred debits and other assets (non-current portion)	$14 million	($8) million	Entergy Wholesale Commodities

Liabilities:
Electricity futures, forwards, swaps, and options	Other current liabilities (current portion)	$2 million	($2 million)	Entergy Wholesale Commodities
Electricity futures, forwards, swaps, and options	Other non-current liabilities (non-current portion)	$7 million	($7) million	Entergy Wholesale Commodities
Natural gas swaps	Other current liabilities	$2 million	($-)	Utility

Instrument	Amount of gain (loss) recognized in OCI (effective portion)	Income Statement location	Amount of gain (loss) reclassified from accumulated OCI into income (effective portion)

2010
Electricity futures, forwards, swaps, and options	$206 million	Competitive businesses operating revenues	$220 million

2009
Electricity futures, forwards, swaps, and options	$315 million	Competitive businesses operating revenues	$322 million

Instrument	Balance Sheet Location	Fair Value	Registrant

Derivatives not designated as hedging instruments

2010
Assets:
Natural gas swaps	Prepayments and other	$0.3 million	Entergy Mississippi

Liabilities:
Natural gas swaps	Other current liabilities	$1.0 million	Entergy Gulf States Louisiana
Natural gas swaps	Other current liabilities	$0.4 million	Entergy Louisiana
Natural gas swaps	Other current liabilities	$0.5 million	Entergy New Orleans

2009
Assets:
Natural gas swaps	Prepayments and other	$2.1 million	Entergy Gulf States Louisiana
Natural gas swaps	Gas hedge contracts	$3.4 million	Entergy Louisiana
Natural gas swaps	Prepayments and other	$2.9 million	Entergy Mississippi

Liabilities:
Natural gas swaps	Other current liabilities	$0.3 million	Entergy Gulf States Louisiana