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 in the United States of America, 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 in the United States of America, 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.

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 proceeding as of the date the financial statements are prepared.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

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, 2012 and 2011, is shown below:

2012	Entergy		Utility		Entergy Wholesale Commodities		Parent & Other
	(In Millions)
Production
Nuclear	$	9,588	$	6,624	$	2,964	$	-
Other		2,878		2,493		385		-
Transmission		3,654		3,619		35		-
Distribution		6,561		6,561		-		-
Other		1,654		1,416		235		3
Construction work in progress		1,366		973		392		1
Nuclear fuel		1,598		907		691		-
Property, plant, and equipment - net	$	27,299	$	22,593	$	4,702	$	4

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

2011	Entergy		Utility		Entergy Wholesale Commodities		Parent & Other
	(In Millions)
Production
Nuclear	$	8,635	$	5,441	$	3,194	$	-
Other		2,431		2,032		399		-
Transmission		3,344		3,309		35		-
Distribution		6,157		6,157		-		-
Other		1,716		1,463		250		3
Construction work in progress		1,780		1,420		359		1
Nuclear fuel		1,546		802		744		-
Property, plant, and equipment - net	$	25,609	$	20,624	$	4,981	$	4

Depreciation rates on average depreciable property for Entergy approximated 2.5% in 2012, 2.6% in 2011, and 2.6% in 2010. Included in these rates are the depreciation rates on average depreciable Utility property of 2.4% in 2012, 2.5% in 2011, and 2.5% 2010, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 3.5% in 2012, 3.9% in 2011, and 3.7% in 2010.

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 $230.4 million and $214.3 million as of December 31, 2012 and 2011, respectively.

Construction expenditures included in accounts payable is $267 million and $171 million at December 31, 2012 and 2011, respectively.

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, 2012 and 2011, is shown below:

2012	Entergy Arkansas		Entergy Gulf States Louisiana		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans			Entergy Texas		System Energy
	(In Millions)
Production
Nuclear	$	1,073	$	1,428	$	2,180	$	-	$	-		$	-	$	1,943
Other		621		286		680		545		(11	)		371		-
Transmission		1,034		573		734		581		27			642		28
Distribution		1,747		939		1,454		1,065		331			1,025		-
Other		115		187		289		201		182			106		17
Construction work in progress		206		125		405		63		11			90		40
Nuclear fuel		304		147		204		-		-			-		253
Property, plant, and equipment - net	$	5,100	$	3,685	$	5,946	$	2,455	$	540		$	2,234	$	2,281

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Notes to Financial Statements

2011	Entergy Arkansas		Entergy Gulf States Louisiana		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans			Entergy Texas		System Energy
	(In Millions)
Production
Nuclear	$	1,034	$	1,458	$	1,561	$	-	$	-		$	-	$	1,388
Other		398		286		679		350		(7	)		325		-
Transmission		942		500		706		510		22			624		5
Distribution		1,700		856		1,304		1,009		298			990		-
Other		173		192		278		206		186			110		18
Construction work in progress		120		122		559		105		14			91		358
Nuclear fuel		273		206		165		-		-			-		158
Property, plant, and equipment - net	$	4,640	$	3,620	$	5,252	$	2,180	$	513		$	2,140	$	1,927

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

2012	2.5%	1.8%	2.4%	2.6%	3.0%	2.4%	2.8%
2011	2.6%	1.8%	2.5%	2.6%	3.0%	2.2%	2.8%
2010	2.9%	1.8%	2.4%	2.6%	3.1%	2.3%	2.9%

Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $142 million and $136 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $2.8 million and $2.7 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $10 million and $9.8 million as of December 31, 2012 and 2011, respectively.

As of December 31, 2012, construction expenditures included in accounts payable are $56.3 million for Entergy Arkansas, $9.7 million for Entergy Gulf States Louisiana, $110.4 million for Entergy Louisiana, $4.8 million for Entergy Mississippi, $1.9 million for Entergy New Orleans, $8.6 million for Entergy Texas, and $13.5 million for System Energy. As of December 31, 2011, construction expenditures included in accounts payable are $14.1 million for Entergy Arkansas, $13.7 million for Entergy Gulf States Louisiana, $27 million for Entergy Louisiana, $4.3 million for Entergy Mississippi, $3.6 million for Entergy New Orleans, $4.3 million for Entergy Texas, and $32.9 million for System Energy.

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, 2012, 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%	$128	$86
	Common Facilities	Coal		15.75%	$33	$22
White Bluff	Units 1 and 2	Coal	1,659	57.00%	$498	$319
Ouachita (2)	Common Facilities	Gas		66.67%	$169	$142
Entergy Gulf States Louisiana -
Roy S. Nelson	Unit 6	Coal	540	40.25%	$250	$170
Roy S. Nelson	Unit 6 Common Facilities	Coal		15.92%	$9	$3
Big Cajun 2	Unit 3	Coal	588	24.15%	$142	$99
Ouachita (2)	Common Facilities	Gas		33.33%	$87	$73
Entergy Louisiana -
Acadia	Common Facilities	Gas		50.00%	$8	$-
Entergy Mississippi -
Independence	Units 1 and 2 and Common Facilities	Coal	1,678	25.00%	$250	$140
Entergy Texas -
Roy S. Nelson	Unit 6	Coal	540	29.75%	$180	$113
Roy S. Nelson	Unit 6 Common Facilities	Coal		11.77%	$6	$2
Big Cajun 2	Unit 3	Coal	588	17.85%	$107	$68
System Energy -
Grand Gulf	Unit 1	Nuclear	1,430(4)	90.00%(3)	$4,557	$2,569

Entergy Wholesale Commodities:
Independence	Unit 2	Coal	842	14.37%	$69	$43
Independence	Common Facilities	Coal		7.18%	$16	$9
Roy S. Nelson	Unit 6	Coal	540	10.9%	$104	$54
Roy S. Nelson	Unit 6 Common Facilities	Coal		4.31%	$2	$1

(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 and not for the generating units.
(3)	Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements.
(4)	Includes estimate, pending further testing, of the rerate for recovered performance (approximately 55 MW) and uprate (approximately 178 MW) completed in 2012.

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Entergy Corporation and Subsidiaries

Notes to 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.

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,
	2012					2011					2010
	(In Millions, Except Per Share Data)
			$/share					$/share					$/share
Net income attributable to Entergy Corporation	$	846.7				$	1,346.4				$	1,250.2

Basic earnings per average common share		177.3	$	4.77			177.4	$	7.59			186.0	$	6.72
Average dilutive effect of:
Stock options		0.3		(0.01	)		1.0		(0.04	)		1.8		(0.06	)
Other equity plans		0.1		-			-		-			-		-
Diluted earnings per average common shares		177.7	$	4.76			178.4	$	7.55			187.8	$	6.66

The calculation of diluted earnings per share excluded 7,164,319 options outstanding at December 31, 2012, 5,712,604 options outstanding at December 31, 2011, and 5,380,262 options outstanding at December 31, 2010 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.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Stock-based Compensation Plans

Entergy grants stock options, restricted stock, performance units, and restricted liability awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over three years.

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 (its regulator) empowered to set rates that bind customers; (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, where specific recovery is not provided for in tariff rates. 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.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

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 portion of River Bend that is not rate-regulated, 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 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 equity unless the unrealized loss is other than temporary and therefore recorded in earnings. 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 is 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.

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 various exceptions including 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 physically 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 to earnings in the periods when the underlying transactions actually occur. 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

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.

Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have applications pending for renewed NRC licenses. Various parties have expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. If the NRC does not renew the operating license for any of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and impairing its value as an asset.

In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years. The renewed operating license expires in March 2032. In May 2011 the Vermont Department of Public Service and the New England Coalition petitioned the United States Court of Appeals for the D.C. Circuit seeking judicial review of the NRC’s issuance of the renewed operating license, alleging that the license had been issued without a valid and effective water quality certification under Section 401 of the Clean Water Act. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. intervened in the proceeding. In June 2012 the Court of Appeals denied the appeal on the ground that the petitioners had failed to exhaust their administrative remedies before the NRC. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired.

Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but has an application pending before the Vermont Public Service Board (VPSB) for a new Certificate of Public Good for operation until March 2032. In April 2011, Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, the owner and operator respectively of Vermont Yankee, filed suit in the United States District Court for the District of Vermont. The suit challenged certain conditions imposed by Vermont upon Vermont Yankee’s continued operation and storage of spent nuclear fuel, including the requirement to obtain not only a new Certificate of Public Good, but also approval by Vermont’s General Assembly. In January 2012 the court entered judgment in Entergy’s favor and specifically:

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

·	Declared that Vermont’s laws requiring Vermont Yankee to cease operation in March 2012 and prohibiting the storage of spent nuclear fuel from operation after that date, absent approval by the General Assembly, were based on radiological safety concerns and are preempted by the Atomic Energy Act;

·	Permanently enjoined Vermont from enforcing these preempted requirements of the state’s laws; and

Permanently enjoined Vermont under the Commerce Clause of the United States Constitution from conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states.

In February 2012 the Vermont defendants appealed the decision to the United States Court of Appeals for the Second Circuit. Vermont Yankee cross-appealed on two grounds: (1) the Federal Power Act alternatively preempts conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states (an issue the District Court found unnecessary to decide in light of its ruling under the Commerce Clause); and (2) a request to make permanent the injunction pending appeal that the District Court entered on March 19, 2012 which prohibits Vermont from enforcing a statutory provision to compel Vermont Yankee to shut down because the cumulative total amount of spent fuel stored at the site exceeds the amount derived from the operation of the facility up to, but not beyond, March 21, 2012 (a provision the enforcement of which the January 2012 decision had not enjoined). The appeal and cross-appeal remain pending.

In January 2012, Entergy filed a motion requesting that the VPSB grant, based on the existing record in its proceeding, Vermont Yankee’s pending application for a new Certificate of Public Good. Entergy subsequently filed another motion asking the VPSB to declare that title 3, section 814(b) of the Vermont statutes (3 V.S.A. § 814(b)) authorized Vermont Yankee to operate while the Certificate of Public Good proceeding was pending because Entergy had timely filed a petition for a new Certificate of Public Good that had not yet been decided. In March 2012 the VPSB issued orders denying Entergy’s motion with respect to 3 V.S.A. § 814(b) but stating that the order did not require Vermont Yankee to cease operations, denying Entergy’s motion to issue a new Certificate of Public Good based on the existing record, determining to open a new docket and to create a new record to decide Vermont Yankee’s request for a new Certificate of Public Good (without prejudice to any rights that Entergy might have under 3 V.S.A. § 814(b)), and directing Entergy to file an amended Certificate of Public Good petition that identified the specific approvals it was seeking in light of the district court’s decision. In April 2012, Entergy filed its amended Certificate of Public Good petition and in June 2012 filed its initial testimony in support of that petition. The VPSB’s current schedule provides for hearings and briefs to be filed through August 2013, but no date for a decision by the VPSB.

In May 2012, Entergy filed a motion asking the VPSB to amend the 2002 and 2006 VPSB orders respectively approving Entergy’s acquisition of Vermont Yankee and Vermont Yankee’s construction of a spent nuclear fuel storage facility. These orders contained conditions respectively precluding the operation of Vermont Yankee after March 21, 2012 absent issuance of a new or renewed certificate of public good and limiting the amount of spent nuclear fuel stored at the site, in each case without explicitly addressing whether those conditions were subject to 3 V.S.A. § 814(b). In its March 2012 order the VPSB had found 3 V.S.A. § 814(b) did not apply to the conditions in those orders even though it did apply to the certificates of public good issued by the orders. In November 2012 the VPSB denied Entergy’s motion to amend the 2002 and 2006 VPSB orders. In December 2012 the Conservation Law Foundation filed a complaint in the Vermont Supreme Court, based on the VPSB’s November order, which sought an order shutting down Vermont Yankee while its Certificate of Public Good application is pending. Entergy moved to dismiss that complaint on the basis, among other grounds, that 3 V.S.A. § 814(b) allows Vermont Yankee to operate while its Certificate of Public Good application is being decided. The Vermont Supreme Court heard oral argument on the motion in January 2013. Also in January 2013, the VPSB issued an order closing the old Certificate of Public Good docket (the one superseded by Entergy’s April 2012 amended petition) in which the VPSB’s March 2012 and November 2012 orders had been issued, making an appeal from those orders ripe. Entergy immediately filed a notice appealing those VPSB orders to the Vermont Supreme Court. Entergy expects to file its appeal brief in March 2013.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

In September 2012, Entergy filed a petition asking the VPSB to issue a Certificate of Public Good allowing construction at Vermont Yankee for a diesel generator to provide power in the event of a station blackout. Vermont Yankee currently can obtain such power from the Vernon Dam. Due to changes instituted by ISO-New England, Vermont Yankee will no longer be able to rely upon the Vernon Dam in the event of a station blackout after August 31, 2013 and therefore plans to install a new diesel generator as a replacement power source. The VPSB requested and received comments on Entergy’s September 2012 petition and its relationship to Entergy’s other petition for a Certificate of Public Good. In December 2012 the VPSB issued an order opening an investigation into Vermont Yankee’s Certificate of Public Good diesel generator application. In February 2013 the VPSB issued a notice allowing comments to be filed by March 15, 2013, but not otherwise establishing a schedule for completing that investigation.

Impairment

Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy has tested the recoverability of the plant and related assets each quarter since the first quarter 2010. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162.0 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge is recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.

The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.

The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:

Significant Unobservable Inputs	Range	Weighted Average

Weighted average cost of capital	7.5%-8.0%	7.8%
Long-term pre-tax operating margin (cash basis)	6.1%-7.8%	7.2%

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors. Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.

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.

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, or over the life of the original debt issuance if the debt is not refinanced, 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 Preferred Stock without Sinking Fund

Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred 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 had protective rights until the securities were repurchased in December 2011), 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, financial position, or cash flows.

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 tables below provide detail of “Other regulatory assets” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2012 and 2011:

Entergy

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	422.6	$	395.9
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC)		6.8		-
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)		35.1		12.4
New nuclear generation development costs (Note 2)		56.8		56.8
Gas hedging costs - recovered through fuel rates		8.3		30.3
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)		2,866.3		2,542.0
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b)		-		2.4
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 – Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators)		970.8		996.4
Removal costs - recovered through depreciation rates (Note 9) (b)		155.7		81.2
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)		22.4		24.3
Spindletop gas storage facility - recovered through December 2032 (a)		29.4		31.0
Transition to competition costs - recovered over a 15-year period through February 2021		82.1		89.2
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)		177.6		198.4
Incremental ice storm costs - recovered through 2032		10.0		10.5
Michoud plant maintenance – recovered over a 7-year period through September 2018		11.0		12.9
Unamortized loss on reacquired debt - recovered over term of debt		95.9		108.8
Other		75.1		44.4
Total	$	5,025.9	$	4,636.9

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Arkansas

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	210.2	$	187.7
Incremental ice storm costs - recovered through 2032		10.0		10.5
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)		831.2		768.3
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery)		17.3		4.6
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b)		-		2.4
Provision for storm damages - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)		115.2		114.7
Unamortized loss on reacquired debt - recovered over term of debt		31.5		34.7
Other		6.2		4.0
Entergy Arkansas Total	$	1,221.6	$	1,126.9

Entergy Gulf States Louisiana

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	6.1	$	12.8
Gas hedging costs - recovered through fuel rates		2.6		8.6
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b)		300.5		231.3
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators)		18.9		10.2
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC)		6.8		-
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)		22.4		24.3
Spindletop gas storage facility - recovered through December 2032 (a)		29.4		31.0
Unamortized loss on reacquired debt - recovered over term of debt		9.9		11.6
Other		13.1		4.1
Entergy Gulf States Louisiana Total	$	409.7	$	333.9

Entergy Louisiana

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	136.9	$	125.8
Gas hedging costs - recovered through fuel rates		3.4		12.4
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b)		475.6		427.9
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)		177.6		198.4
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators)		74.5		9.7
Unamortized loss on reacquired debt - recovered over term of debt		17.6		20.0
Other		28.0		20.3
Entergy Louisiana Total	$	913.6	$	814.5

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Mississippi

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	5.6	$	5.3
Gas hedging costs - recovered through fuel rates		2.2		7.8
Removal costs - recovered through depreciation rates (Note 9) (b)		57.4		48.5
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)		17.8		7.8
New nuclear generation development costs (Note 2)		56.8		56.8
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)		234.6		221.1
Provision for storm damages - recovered through retail rates		9.2		30.7
Unamortized loss on reacquired debt - recovered over term of debt		9.6		10.7
Other		8.3		4.7
Entergy Mississippi Total	$	401.5	$	393.4

Entergy New Orleans

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	3.6	$	3.4
Removal costs - recovered through depreciation rates (Note 9) (b)		29.9		16.3
Gas hedging costs - recovered through fuel rates		-		1.5
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)		134.6		127.6
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators)		15.1		8.6
Unamortized loss on reacquired debt - recovered over term of debt		2.3		2.6
Michoud plant maintenance – recovered over a 7-year period through September 2018		11.0		12.9
Other		5.5		5.9
Entergy New Orleans Total	$	202.0	$	178.8

Entergy Texas

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	1.2	$	1.3
Removal costs - recovered through depreciation rates (Note 9) (b)		11.5		4.5
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)		258.8		244.9
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators)		737.9		822.5
Transition to competition costs - recovered over a 15-year period through February 2021		82.1		89.2
Unamortized loss on reacquired debt - recovered over term of debt		9.4		10.8
Other		13.6		4.9
Entergy Texas Total	$	1,114.5	$	1,178.1

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

System Energy

	2012		2011
	(In Millions)
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b)	$	58.9	$	59.6
Removal costs - recovered through depreciation rates (Note 9) (b)		56.8		11.8
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b)		198.2		197.6
Unamortized loss on reacquired debt - recovered over term of debt		15.6		18.2
Other		0.6		0.6
System Energy Total	$	330.1	$	287.8

(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 occurs 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.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy's service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy Arkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.

The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.

Entergy recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy recorded corresponding regulatory assets of approximately $120 million and construction work in progress of approximately $250 million. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.

Correction of Regulatory Asset for Income Taxes

In the first quarter 2012, Entergy Gulf States Louisiana determined that its regulatory asset for income taxes was overstated because of a difference between the regulatory treatment of the income taxes associated with certain items (primarily pension expense) and the financial accounting treatment of those taxes. Beginning with Louisiana retail rate filings using the 1994 test year, retail rates were developed using the normalization method of accounting for income taxes. With respect to these items, however, the financial accounting for income taxes was computed using the flow-through method of accounting. As a result, over the years Entergy Gulf States Louisiana accumulated a regulatory asset representing the expected future recovery of tax expense for the affected items even though the tax expense was being collected currently in rates from customers and would not be recovered in the future.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

The effect was immaterial to the consolidated balance sheets, results of operations, and cash flows of Entergy for all prior reporting periods and on a cumulative basis. Therefore, a cumulative adjustment was recorded in the first quarter 2012 to remove the regulatory asset previously recorded. This adjustment increased 2012 income tax expense by $46.3 million, decreased the regulatory asset for income taxes by $75.3 million, and decreased accumulated deferred income taxes by $29 million.

The effect was also immaterial to the balance sheets, results of operations, and cash flows of Entergy Gulf States Louisiana for all prior reporting periods. Correcting the cumulative effect of the error in the first quarter 2012 could have been material to the 2012 results of operations of Entergy Gulf States Louisiana and, therefore, Entergy Gulf States Louisiana is revising its prior period financial statements to correct the errors. The corrections affect the prior period financial statements of Entergy Gulf States Louisiana as shown in the tables below:

	Years Ended December 31,
	2011						2010
	As previously reported			As corrected			As previously reported		As corrected
	(In Thousands)

Income Statement
Income taxes	$	88,313		$	89,736		$	75,878	$	92,297
Net income	$	203,027		$	201,604		$	190,738	$	174,319
Earnings applicable to common equity	$	202,202		$	200,779		$	189,911	$	173,492

Statement of Cash Flows
Net income	$	203,027		$	201,604		$	190,738	$	174,319
Deferred income taxes, investment tax credits, and non-current taxes accrued	$	(6,268	)	$	(4,845	)	$	87,920	$	104,339
Changes in other regulatory assets	$	(80,027	)	$	(77,713	)	$	114,528	$	141,216
Other operating activities	$	(35,248	)	$	(37,562	)	$	30,717	$	4,029

	December 31, 2011
	As previously reported		As corrected

Balance Sheet
Regulatory asset for income taxes - net	$	249,058	$	173,724
Accumulated deferred income taxes - current	$	5,427	$	5,107
Accumulated deferred income taxes and taxes accrued	$	1,397,230	$	1,368,563
Member’s equity	$	1,439,733	$	1,393,386

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

	Years Ended December 31, 2011 and 2010
	Member’s Equity				Total Equity
	As previously reported		As corrected		As previously reported		As corrected
	(In Thousands)

Statement of Changes in Equity
Balance at December 31, 2009	$	1,473,930	$	1,445,425	$	1,441,759	$	1,413,254
2010 Net income	$	190,738	$	174,319	$	190,738	$	174,319
Balance at December 31, 2010	$	1,539,517	$	1,494,593	$	1,509,213	$	1,464,289
2011 Net income	$	203,027	$	201,604	$	203,027	$	201,604
Balance at December 31, 2011	$	1,439,733	$	1,393,386	$	1,380,123	$	1,333,776

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 generally 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, 2012 and 2011 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.

	2012			2011
	(In Millions)

Entergy Arkansas	$	97.3		$	209.8
Entergy Gulf States Louisiana (a)	$	99.2		$	2.9
Entergy Louisiana (a)	$	94.6		$	1.5
Entergy Mississippi	$	26.5		$	(15.8	)
Entergy New Orleans (a)	$	1.9		$	(7.5	)
Entergy Texas	$	(93.3	)	$	(64.7	)

(a)

2012 and 2011 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 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 costs 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.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

In 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 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.

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 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 billing month based upon the level of such costs incurred two months prior to the billing 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 included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.

In December 2011 the LPSC authorized its staff to initiate another 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 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.

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. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1.0 million from Entergy Louisiana’s fuel adjustment clause to base rates. Two parties have intervened in the proceeding. A procedural schedule has not yet been established. Entergy Louisiana has recorded provisions for the estimated outcome of this proceeding.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

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 complaint 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. In December 2008 the defendant Entergy companies removed the attorney general’s suit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.

The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. 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. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.

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.

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.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, 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 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. 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, including interest, 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 fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.

In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.

In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013.

In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings”. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.

In November 2012, Entergy Texas filed a pleading seeking a PUCT finding that special circumstances exist for limited cost recovery of capacity costs associated with two power purchase agreements until such time that these costs are included in base rates or a purchased capacity recovery rider or other recovery mechanism.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Retail Rate Proceedings

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.

2013 Base Rate Filing

On December 31, 2012, in accordance with the requirements of Arkansas law, Entergy Arkansas filed with the APSC notice of its intent to file an application for a general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the date of its notice.

Filings with the LPSC

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 formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the 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.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.

In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.11% earned 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 also reflects a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.

In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate change was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.

In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.

Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:

·	authorization to increase the revenue it collects from customers by approximately $28 million;

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement;

·	authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and,

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:

·	authorization to increase the revenue it collects from customers by approximately $24 million;

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

(Entergy Louisiana)

In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and 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 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.

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.

In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

In May 2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.07% earned return on common equity, which is just outside of the allowed earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed a joint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, and the LPSC approved the joint report in October 2011.

In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.

In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Louisiana.

Under its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:

·	authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement;

·	authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and,

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:

·	authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Retail Rates - Gas (Entergy Gulf States Louisiana)

In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.

Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.

In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.

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. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.

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.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

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.

In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.

In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.

Filings with the City Council (Entergy New Orleans)

Formula Rate Plan

In April 2009 the City Council approved a new three-year formula rate plan for Entergy New Orleans, 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 was over- or under-earning. The formula rate plan also included 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.

In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.

Table of Contents

Entergy Corporation and Subsidiaries

Notes to Financial Statements

In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.

A 2008 rate case settlement 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.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2009 Rate Case

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 included 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 provided 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 stipulated an authorized return on equity of 10.125%. The settlement stated 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 set 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.

2011 Rate Case

In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate

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proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.

In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.

System Agreement Cost Equalization Proceedings

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. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.

In June 2005, the FERC issued a decision in 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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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 Arkansas Electric Energy Consumers appealed the FERC’s December 2005 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 concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.

In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.

In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:

	Payments or (Receipts)
	(In Millions)
Entergy Arkansas	$	156
Entergy Gulf States Louisiana	$	(75	)
Entergy Louisiana	$	-
Entergy Mississippi	$	(33	)
Entergy New Orleans	$	(5	)
Entergy Texas	$	(43	)

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Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.

Calendar Year 2012 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 2012 production costs were recorded in December 2012, 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 2013.

	Payments or (Receipts)
	(In Millions)
Entergy Arkansas	$	-
Entergy Gulf States Louisiana	$	-
Entergy Louisiana	$	-
Entergy Mississippi	$	-
Entergy New Orleans	$	(17	)
Entergy Texas	$	17

The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the Utility operating companies’ 2012 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 Pmts (Rcts)			2008 Pmts (Rcts)			2009 Pmts (Rcts)			2010 Pmts (Rcts)			2011 Pmts (Rcts)			2012 Pmts (Rcts)
	(In Millions)

Entergy Arkansas	$	252		$	252		$	390		$	41		$	77		$	41
Entergy Gulf States La.	$	(120	)	$	(124	)	$	(107	)	$	-		$	(12	)	$	-
Entergy Louisiana	$	(91	)	$	(36	)	$	(140	)	$	(22	)	$	-		$	(41	)
Entergy Mississippi	$	(41	)	$	(20	)	$	(24	)	$	(19	)	$	(40	)	$	-
Entergy New Orleans	$	-		$	(7	)	$	-		$	-		$	(25	)	$	-
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

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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 trapped costs at Entergy Arkansas related to its contract with AmerenUE.

Entergy Arkansas, and, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas, and, for December 2012, Entergy Texas, records a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. 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 concluded, 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 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. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, 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.

In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to

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AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing "Entergy bandwidth proceedings."

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.

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. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.

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 submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.

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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. 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. In March 2011 the ALJ issued an order placing this proceeding in abeyance.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the FERC on review.

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.

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 in June 2009. 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 requested rehearing of the

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FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. On October 6, 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.

In September 2010, the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.

Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.

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.

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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 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. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.

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 disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.

The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.

As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative rerun of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages that should be paid by Entergy Arkansas to the Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans; and that Entergy Arkansas “shareholders” should pay Entergy Arkansas customers $34 million. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. A hearing is scheduled for May 2013, and the ALJ’s initial decision on the calculation of the effects is due by August 28, 2013.

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

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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.

Entergy Arkansas December 2012 Winter Storm

In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm are estimated to be in the range of $55 million to $65 million. Entergy Arkansas recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Arkansas recorded corresponding regulatory assets of approximately $21 million and construction work in progress of approximately $37 million. Entergy Arkansas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Arkansas has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Arkansas is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery. Entergy Arkansas plans to present a cost recovery proposal to the APSC in a base rate case filing in March 2013.

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.

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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.

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

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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 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. In February 2012, Entergy Gulf States Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units. The 500,000 preferred membership units are mandatorily redeemable in January 2112.

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.

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In October 2006, the City Council approved a rate filing settlement agreement that, among other things, 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 that began in March 2007. These storm reserve funds are held in a restricted escrow account until needed in response to a storm. In November 2012, Entergy New Orleans withdrew $10 million from the storm reserve escrow account to partially offset the costs associated with Hurricane Isaac.

New Nuclear Generation Development Costs

Entergy Gulf States Louisiana and Entergy Louisiana

Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In March 2010, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. The testimony and legal briefs of the LPSC staff generally support the request of Entergy Gulf States Louisiana and Entergy Louisiana, although other parties filed briefs, without supporting testimony, in opposition to the request. At an evidentiary hearing in October 2011, Entergy Gulf States Louisiana, Entergy Louisiana, and the LPSC staff presented testimony in support of certification of activities to preserve an option for a new nuclear plant at River Bend. The ALJ recommended, however, that the LPSC decline the request of Entergy Gulf States Louisiana and Entergy Louisiana on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. There has been no suggestion that the planning activities or costs incurred were imprudent. At its June 28, 2012 meeting the LPSC voted to uphold the ALJ’s decision and directed that Entergy Gulf States Louisiana and Entergy Louisiana be permitted to seek recovery of these costs in their anticipated, upcoming rate case filings, fully reserving the LPSC’s right to determine the recoverability of such costs in rates. On September 10, 2012, Entergy Gulf States Louisiana and Entergy Louisiana filed a petition for appeal and judicial review of the LPSC’s order with the Louisiana Nineteenth Judicial District Court. A schedule for the appeal has not been established. In their rate cases filed in February 2013, Entergy Gulf States Louisiana and Entergy Louisiana request recovery of their new nuclear generation development costs over a ten-year amortization period, with the costs included in rate base.

Entergy Mississippi

Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi has been developing and is preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. This project is in the early stages, and several issues remain to be addressed over time before significant additional capital would be committed to this project. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it is in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation states that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf. The costs shall be treated as a regulatory asset until the proceeding is resolved. The Mississippi Public Utilities Staff and Entergy Mississippi also agree that the MPSC should conduct a hearing to consider the relief requested by Entergy Mississippi in its application, including evidence regarding whether costs incurred in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf were prudently incurred and are otherwise allowable. The Mississippi Public Utilities Staff and Entergy Mississippi further agree that such prudently incurred costs shall be recoverable in a manner to be determined by the MPSC. In the Stipulation, the Mississippi Public Utilities Staff and Entergy Mississippi agree that the development of a nuclear unit project

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option is consistent with the Mississippi Baseload Act. The Mississippi Public Utilities Staff and Entergy Mississippi further agree that the deferral of costs incurred in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf also is consistent with the Mississippi Baseload Act. Entergy Mississippi will not accrue carrying charges or continue to accrue AFUDC on the costs, pending the outcome of the proceeding. Further proceedings before the MPSC have not been scheduled.

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 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 was 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 less expensive power offered from off-system suppliers. 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 in March 2012 the court found that the case met the requirements to be maintained as a class action under Texas law. On April 30, 2012, the court entered an order certifying the class. The defendants have appealed the order to the Texas Court of Appeals – First District. The appeal is pending and proceedings in district court are stayed until the appeal is resolved.

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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 has 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 fair value of the trust assets is determined by the trustee and certain investment managers. The trustee 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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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 2012, 2011, and 2010 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

	2012	2011	2010
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period	$150,763	$121,961	$104,956
Interest cost on projected benefit obligation	260,929	236,992	231,206
Expected return on assets	(317,423)	(301,276)	(259,608)
Amortization of prior service cost	2,733	3,350	4,658
Recognized net loss	167,279	92,977	65,901
Net periodic pension costs	$264,281	$154,004	$147,113

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss	$552,303	$1,045,624	$232,279
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(2,733)	(3,350)	(4,658)
Amortization of net loss	(167,279)	(92,977)	(65,901)
Total	382,291	949,297	161,720

Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)	$646,572	$1,103,301	$308,833

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Prior service cost	$2,268	$2,733	$3,350
Net loss	$219,805	$169,064	$92,977

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The Registrant Subsidiaries’ total 2012, 2011, and 2010 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:

2012	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	$22,169	$12,273	$14,675	$6,410	$2,824	$5,684	$5,920
Interest cost on projected benefit obligation	55,686	25,679	35,201	16,279	7,608	16,823	12,987
Expected return on assets	(65,763)	(34,370)	(40,836)	(20,945)	(8,860)	(22,325)	(16,436)
Amortization of prior service cost	200	19	208	30	7	15	13
Recognized net loss	40,772	16,173	28,197	10,532	6,878	10,179	9,001
Net pension cost	$53,064	$19,774	$37,445	$12,306	$8,457	$10,376	$11,485

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss	$105,133	$77,207	$76,163	$27,106	$14,282	$28,745	$10,266
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(200)	(19)	(208)	(30)	(7)	(15)	(13)
Amortization of net loss	(40,772)	(16,173)	(28,197)	(10,532)	(6,878)	(10,179)	(9,001)
Total	$64,161	$61,015	$47,758	$16,544	$7,397	$18,551	$1,252

Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)	$117,225	$80,789	$85,203	$28,850	$15,854	$28,927	$12,737

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Prior service cost	$23	$9	$83	$10	$2	$6	$10
Net loss	$50,175	$23,731	$34,906	$13,375	$8,046	$13,494	$9,717

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2011	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	$18,072	$9,848	$11,543	$5,308	$2,242	$4,788	$4,941
Interest cost on projected benefit obligation	51,965	23,713	32,636	15,637	7,050	15,971	11,758
Expected return on assets	(62,434)	(33,358)	(38,866)	(20,152)	(8,455)	(22,005)	(15,138)
Amortization of prior service cost	459	79	280	152	35	65	16
Recognized net loss	25,681	9,118	17,990	6,717	4,666	5,579	5,284
Net pension cost	$33,743	$9,400	$23,583	$7,662	$5,538	$4,398	$6,861

Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss	$217,989	$102,329	$137,100	$56,714	$29,297	$64,662	$52,876
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(459)	(79)	(280)	(152)	(35)	(65)	(16)
Amortization of net loss	(25,681)	(9,118)	(17,990)	(6,717)	(4,666)	(5,579)	(5,284)
Total	$191,849	$93,132	$118,830	$49,845	$24,596	$59,018	$47,576

Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)	$225,592	$102,532	$142,413	$57,507	$30,134	$63,416	$54,437

Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Prior service cost	$200	$19	$208	$30	$7	$15	$13
Net loss	$41,309	$16,295	$28,486	$10,667	$6,935	$10,261	$9,135

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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

Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet for Entergy Corporation and its Subsidiaries as of December 31, 2012 and 2011

	December 31,
	2012	2011
	(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at beginning of year	$5,187,635	$4,301,218
Service cost	150,763	121,961
Interest cost	260,929	236,992
Actuarial loss	693,017	703,895
Employee contributions	789	828
Benefits paid	(196,494)	(177,259)
Balance at end of year	$6,096,639	$5,187,635

Change in Plan Assets
Fair value of assets at beginning of year	$3,399,916	$3,216,268
Actual return on plan assets	458,137	(40,453)
Employer contributions	170,512	400,532
Employee contributions	789	828
Benefits paid	(196,494)	(177,259)
Fair value of assets at end of year	$3,832,860	$3,399,916

Funded status	($2,263,779)	($1,787,719)

Amount recognized in the balance sheet
Non-current liabilities	($2,263,779)	($1,787,719)

Amount recognized as a regulatory asset
Prior service cost	$308	$9,836
Net loss	2,352,234	2,048,743
	$2,352,542	$2,058,579
Amount recognized as AOCI (before tax)
Prior service cost	$9,444	$2,648
Net loss	633,146	551,613
	$642,590	$554,261

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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, 2012 and 2011

2012	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	$1,116,572	$512,432	$704,748	$326,377	$151,966	$337,669	$258,268
Service cost	22,169	12,273	14,675	6,410	2,824	5,684	5,920
Interest cost	55,686	25,679	35,201	16,279	7,608	16,823	12,987
Actuarial loss	134,691	92,275	93,817	36,329	18,000	38,328	13,691
Benefits paid	(54,232)	(19,591)	(30,696)	(15,543)	(5,813)	(16,328)	(8,025)
Balance at end of year	$1,274,886	$623,068	$817,745	$369,852	$174,585	$382,176	$282,841

Change in Plan Assets
Fair value of assets at beginning of year	$707,275	$366,555	$432,418	$223,981	$94,202	$237,438	$147,091
Actual return on plan assets	95,321	49,438	58,489	30,169	12,578	31,909	19,860
Employer contributions	37,163	13,569	28,816	9,665	5,811	9,091	9,771
Benefits paid	(54,232)	(19,591)	(30,696)	(15,543)	(5,813)	(16,328)	(8,025)
Fair value of assets at end of year	$785,527	$409,971	$489,027	$248,272	$106,778	$262,110	$168,697

Funded status	($489,359)	($213,097)	($328,718)	($121,580)	($67,807)	($120,066)	($114,144)

Amounts recognized in the balance sheet (funded status)
Non-current liabilities	($489,359)	($213,097)	($328,718)	($121,580)	($67,807)	($120,066)	($114,144)

Amounts recognized as regulatory asset
Prior service cost	$23	$8	$83	$10	$2	$7	$6
Net loss	683,790	283,847	456,800	185,903	103,072	189,589	166,276
	$683,813	$283,855	$456,883	$185,913	$103,074	$189,596	$166,282

Amounts recognized as AOCI (before tax)
Prior service cost	$-	$1	$-	$-	$-	$-	$-
Net loss	-	42,414	-	-	-	-	-
	$-	$42,415	$-	$-	$-	$-	$-

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Notes to Financial Statements

2011	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	$950,595	$431,870	$596,730	$286,179	$128,477	$292,551	$213,098
Service cost	18,072	9,848	11,543	5,308	2,242	4,788	4,941
Interest cost	51,965	23,713	32,636	15,637	7,050	15,971	11,758
Actuarial loss	146,514	65,000	93,175	33,865	19,695	40,122	35,775
Benefits paid	(50,574)	(17,999)	(29,336)	(14,612)	(5,498)	(15,763)	(7,304)
Balance at end of year	$1,116,572	$512,432	$704,748	$326,377	$151,966	$337,669	$258,268

Change in Plan Assets
Fair value of assets at beginning of year	$646,491	$361,207	$406,216	$212,122	$88,688	$237,502	$128,007
Actual return on plan assets	(9,042)	(3,971)	(5,059)	(2,698)	(1,148)	(2,536)	(1,963)
Employer contributions	120,400	27,318	60,597	29,169	12,160	18,235	28,351
Benefits paid	(50,574)	(17,999)	(29,336)	(14,612)	(5,498)	(15,763)	(7,304)
Fair value of assets at end of year	$707,275	$366,555	$432,418	$223,981	$94,202	$237,438	$147,091

Funded status	($409,297)	($145,877)	($272,330)	($102,396)	($57,764)	(($100,231)	($111,177)

Amounts recognized in the balance sheet (funded status)
Non-current liabilities	($409,297)	($145,877)	($272,330)	($102,396)	($57,764)	($100,231)	($111,177)

Amounts recognized as regulatory asset
Prior service cost	$223	$23	$291	$39	$10	$22	$19
Net loss	619,430	214,833	408,835	169,329	95,667	171,023	165,011
	$619,653	$214,856	$409,126	$169,368	$95,677	$171,045	$165,030

Amounts recognized as AOCI (before tax)
Prior service cost	$-	$6	$-	$-	$-	$-	$-
Net loss	-	50,393	-	-	-	-	-
	$-	$50,399	$-	$-	$-	$-	$-

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Notes to Financial Statements

Other Postretirement Trusts

2012	Level 1		Level 2		Level 3	Total
	(In Thousands)
Equity securities:
Common collective trust	$-		$314,478	(c)	$-	$314,478
Fixed income securities:
U.S. Government securities	36,392	(b)	43,398	(a)	-	79,790
Corporate debt instruments	-		42,163	(a)	-	42,163
Registered investment companies	3,229	(d)	-		-	3,229
Other	-		39,846	(f)	-	39,846
Total investments	$39,621		$439,885		$-	$479,506

Other pending transactions						158
Plus: Other postretirement assets included in the investments of the qualified pension trust						8,784
Total fair value of other postretirement assets						$488,448

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Notes to Financial Statements

2011	Level 1		Level 2		Level 3	Total
	(In Thousands)
Equity securities:
Common collective trust	$-		$208,812	(c)	$-	$208,812
Fixed income securities:
U.S. Government securities	42,577	(b)	57,151	(a)	-	99,728
Corporate debt instruments	-		42,807	(a)	-	42,807
Registered investment companies	4,659	(d)	-		-	4,659
Other	-		69,287	(f)	-	69,287
Total investments	$47,236		$378,057		$-	$425,293

Other pending transactions						(235)
Plus: Other postretirement assets included in the investments of the qualified pension trust						2,114
Total fair value of other postretirement assets						$427,172

(a)	Certain preferred stocks and fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes.
(b)	Common stocks, treasury notes and bonds, and certain preferred stocks and fixed income debt securities are stated at fair value determined by quoted market prices.
(c)	The common collective trusts hold investments in accordance with stated objectives. The investment strategy of the trusts is 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 estimate fair value.
(d)	The registered investment company is a money market mutual fund with a stable net asset value of one dollar per share.
(e)	The registered investment company holds investments in domestic and international bond markets and estimates fair value using net asset value per share.
(f)	The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes.
(g)	The unallocated insurance contract investments are recorded at contract value, which approximates fair value. The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust.

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $5.4 billion and $4.6 billion at December 31, 2012 and 2011, respectively.

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Notes to Financial Statements

The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries as of December 31, 2012 and 2011 was as follows:

	December 31,
	2012	2011
	(In Thousands)

Entergy Arkansas	$1,161,448	$1,013,605
Entergy Gulf States Louisiana	$559,190	$459,037
Entergy Louisiana	$735,376	$632,759
Entergy Mississippi	$336,099	$296,259
Entergy New Orleans	$157,233	$136,390
Entergy Texas	$350,351	$308,628
System Energy	$251,378	$227,617

Estimated Future Benefit Payments

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2012, 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)
2013	$195,907	$62,087	$74,981	$7,875
2014	$209,807	$12,440	$79,073	$8,641
2015	$224,922	$13,412	$83,788	$9,476
2016	$242,186	$10,174	$88,458	$10,358
2017	$261,448	$12,248	$94,340	$11,314
2018 - 2022	$1,648,774	$67,055	$566,249	$72,926

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)
2013	$53,108	$19,664	$31,021	$15,356	$5,906	$16,341	$8,067
2014	$54,438	$20,964	$32,216	$16,248	$6,221	$17,067	$8,571
2015	$56,495	$22,611	$33,392	$17,148	$6,660	$17,906	$9,083
2016	$58,770	$24,361	$34,867	$18,170	$7,125	$18,777	$9,772
2017	$61,203	$26,293	$36,648	$19,171	$7,691	$19,778	$10,393
2018 - 2022	$357,927	$166,599	$216,903	$110,145	$48,039	$114,345	$70,026

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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)
2013	$208	$257	$18	$118	$25	$853
2014	$357	$267	$16	$114	$24	$789
2015	$335	$247	$15	$110	$24	$756
2016	$289	$239	$13	$103	$23	$891
2017	$288	$284	$12	$100	$23	$766
2018 - 2022	$1,846	$1,004	$41	$601	$196	$3,304

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)
2013	$16,034	$8,381	$10,174	$4,624	$4,859	$6,942	$2,423
2014	$16,442	$8,867	$10,588	$4,901	$4,937	$7,218	$2,563
2015	$17,094	$9,499	$10,980	$5,194	$5,025	$7,536	$2,755
2016	$17,650	$10,087	$11,440	$5,482	$5,097	$7,894	$2,894
2017	$18,334	$10,745	$11,978	$5,811	$5,196	$8,331	$3,136
2018 - 2022	$101,723	$64,193	$69,660	$33,712	$26,592	$47,415	$19,435

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)
2013	$1,889	$835	$1,022	$584	$478	$722	$265
2014	$2,027	$910	$1,101	$639	$497	$770	$297
2015	$2,180	$992	$1,186	$691	$515	$821	$331
2016	$2,335	$1,079	$1,274	$747	$533	$874	$368
2017	$2,500	$1,172	$1,370	$805	$551	$928	$408
2018 - 2022	$15,201	$7,446	$8,492	$4,912	$2,991	$5,463	$2,797

Contributions

Entergy currently expects to contribute approximately $163.3 million to its qualified pension plans and approximately $82.5 million to other postretirement plans in 2013. The expected 2013 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, 2013 valuations are completed by April 1, 2013.

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Notes to Financial Statements

The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans in 2013:

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

Pension Contributions	$34,945	$11,198	$20,731	$7,969	$3,959	$6,666	$7,621
Other Postretirement Contributions	$26,675	$8,381	$10,173	$5,469	$3,669	$5,153	$4,090

Actuarial Assumptions

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2012, and 2011 were as follows:

	2012	2011

Weighted-average discount rate:
Qualified pension	4.31% - 4.50%	5.10% - 5.20%
Other postretirement	4.36%	5.10%
Non-qualified pension	3.37%	4.40%
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 2012, 2011, and 2010 were as follows:

	2012	2011	2010

Weighted-average discount rate:
Qualified pension	5.10% - 5.20%	5.60% - 5.70%	6.10% - 6.30%
Other postretirement	5.10%	5.50%	6.10%
Non-qualified pension	4.40%	4.90%	5.40%
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	8.50%	7.75%	7.75%
Other postretirement taxable assets	6.50%	5.50%	5.50%

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

The assumed health care cost trend rate used in measuring Entergy’s December 31, 2012 APBO was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. The assumed health care cost trend rate used in measuring Entergy’s 2012 Net Other Postretirement Benefit Cost was 7.75% for pre-65 retirees and 7.50% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for pre-65 retirees and 4.75% in 2022 and beyond for post-65 retirees. A one percentage point change in the assumed health care cost trend rate for 2012 would have the following effects:

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Notes to Financial Statements

	1 Percentage Point Increase		1 Percentage Point Decrease
2012	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	$274,059	$28,455	($220,654)	($22,210)

A one percentage point change in the assumed health care cost trend rate for 2012 would have the following effects for the Registrant Subsidiaries:

	1 Percentage Point Increase		1 Percentage Point Decrease
2012	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	$41,816	$3,994	($33,880)	($3,138)
Entergy Gulf States Louisiana	$31,702	$3,287	($25,554)	($2,568)
Entergy Louisiana	$30,780	$3,237	($24,858)	($2,528)
Entergy Mississippi	$13,728	$1,346	($11,139)	($1,057)
Entergy New Orleans	$8,410	$779	($6,924)	($619)
Entergy Texas	$19,647	$1,799	($16,034)	($1,421)
System Energy	$11,304	$1,279	($9,027)	($994)

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, 2012 and 2011 Accumulated Postretirement Benefit Obligation by $316.6 million and $274 million, respectively, and reduced the 2012, 2011, and 2010 other postretirement benefit cost by $31.2 million, $33.0 million, and $26.6 million, respectively. In 2012, Entergy received $6 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 12/31/2012 APBO	($62,877)	($32,055)	($36,015)	($19,507)	($10,902)	($21,164)	($13,586)
Impact on 12/31/2011 APBO	($55,684)	($27,834)	($31,693)	($17,687)	($10,500)	($19,346)	($11,036)

Impact on 2012 other postretirement benefit cost	($5,791)	($3,660)	($3,643)	($1,799)	($995)	($1,321)	($1.400)
Impact on 2011 other postretirement benefit cost	($6,309)	($3,923)	($3,889)	($2,016)	($1,170)	($1,528)	($1,403)
Impact on 2010 other postretirement benefit cost	($5,254)	($3,401)	($3,143)	($1,649)	($1,070)	($1,109)	($1,068)

Medicare subsidies received in 2012	$1,331	$779	$908	$434	$396	$644	$170

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 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. Effective June 3, 2010, employees participating in the Savings Plan of Entergy Corporation and Subsidiaries II (Savings Plan II) were transferred into the System Savings Plan when Savings Plan II merged into the System Savings Plan.

Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $43.7 million in 2012, $42.6 million in 2011, and $41.8 million in 2010. The majority of the contributions were to the System Savings Plan.

The Registrant Subsidiaries’ 2012, 2011, and 2010 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)

2012	$3,223	$1,842	$2,327	$1,875	$740	$1,601
2011	$3,183	$1,804	$2,260	$1,894	$725	$1,613
2010	$3,177	$1,792	$2,289	$1,886	$683	$1,626

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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 reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and 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. Entergy Mississippi currently obtains recovery under a formula rate plan. In the event that this formula rate plan is ever terminated, Entergy Mississippi would at that time operate exclusively in the more traditional rate case environment.

In January 2013, Entergy Gulf States Louisiana’s and Entergy Louisiana’s current formula rate plans expired, and each company filed full rate cases in February 2013. As part of the rate cases that Entergy Louisiana and Entergy Gulf States Louisiana filed, each company requested that the LPSC approve new formula rate plans. Entergy Louisiana and Entergy Gulf States Louisiana cannot predict the outcome of this request. In addition, Entergy New Orleans’ formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility, which is currently expected in the first quarter of 2015.

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.

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Entergy Corporation, Utility operating companies, and System Energy

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 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 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 could 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.

In 2007 through 2012, 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 and timing 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, could be 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) on Entergy and the Utility operating companies.

Based upon the effect of the FERC decision described in the preceding risk factor, in December 2005, Entergy Arkansas provided notice 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, and the U.S. Court of Appeals for the D.C. Circuit has denied appeals of FERC’s decision filed by the LPSC and City Council. In January 2013 the LPSC and City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.

The Utility operating companies have concluded that joining the MISO RTO is in the best interest of all stakeholders and have filed applications with their retail regulators seeking to join the MISO RTO by December 2013. To that end, the Utility operating companies have received orders from their respective retail regulators granting their respective requests to join MISO, subject to certain conditions. The Utility operating companies have also filed with FERC amendments to the System Agreement under

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Section 205 of the Federal Power Act. The amendments allocate certain charges and credits from MISO settlement statements to the Utility operating companies that participate in the System Agreement and address Entergy Arkansas’s withdrawal from the System Agreement. Certain FERC filings related to the rates, terms, and conditions of integrating the Utility operating companies into MISO are planned for early-mid 2013. Entergy cannot predict when or whether the Utility operating companies will satisfy the conditions of the retail regulatory orders or obtain FERC approvals related to the rates, terms, and conditions under which the Utility operating companies will join MISO or when the Utility operating companies’ generation and transmission systems can be fully integrated into the MISO RTO. Moreover, if the operating companies are not successful in joining MISO, alternative or additional arrangements will need to be implemented to allow Entergy Arkansas, and eventually Entergy Mississippi, to operate independent of the System Agreement after these companies terminate their participation in the System Agreement, and the effect such arrangements (or the absence thereof) will have on Entergy or the Utility operating companies is uncertain.

For further information regarding the FERC and APSC proceedings relating to the System Agreement and Entergy’s proposal to join MISO, see the “Rate, Cost-recovery, and Other Regulation – Federal Regulation – System Agreement” and “ – Entergy’s Proposal to Join MISO” sections of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.

The arrangement for the operation of the Utility operating companies’ transmission system faces regulatory and operating challenges and uncertainty in connection with the Utility operating companies’ proposal to move to the MISO RTO.

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 Southwest Power Pool (SPP), a regional transmission organization, 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, retained an independent entity to conduct 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 later expanded to consider Entergy joining the MISO RTO as another alternative. On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining the MISO RTO. In May 2011 the Utility operating companies submitted to each of their respective retail regulators the cost-benefit analysis comparing the option of continuing with the ICT arrangement to joining the SPP RTO or the MISO RTO. The Utility operating companies have received orders from their respective retail regulators granting their respective requests to join MISO, subject to certain conditions. The target implementation date for joining the MISO RTO is December 2013. For further information regarding the FERC and proceedings related to the ICT and MISO, 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 the conditions of the retail regulators’ orders granting the Utility operating companies’ requests to transfer control of their transmission assets to MISO will be satisfied in a timely manner and, if the conditions are satisfied, the nature and effect of any operational challenges the Utility operating companies might face in connection with integration into the MISO RTO. For the period of time prior to integration of all of the Utility operating companies into the MISO RTO or in

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the event all necessary approvals to participate in the MISO RTO are not obtained in a timely manner, the Utility operating companies have received the necessary regulatory approvals to change provider of ICT services from SPP to MISO. MISO began providing ICT services to the Utility operating companies on December 1, 2012 and is under contract to continue to provide those services until December 31, 2014, in the event that some or all of the Utility operating companies are not integrated into MISO by December 2013. To the extent some or all of the Utility operating companies are not integrated into MISO by December 2014, an extension of the current ICT arrangement or the establishment of a similar arrangement with another qualified entity 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.

(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 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 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 effect on Entergy and those Utility operating companies affected by severe weather.

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 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 can 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 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, a portion of which may be capped through the use of risk management products, if capacity factors decrease.

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Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities’ nuclear plant owners periodically shut down 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 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 average 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 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 2013. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy also may draw upon its own inventory intended for later generation periods, depending upon its risk management strategy 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 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 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 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 affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities. For example, the earthquake of March 11, 2011 that affected the Fukushima Daiichi nuclear plants in Japan resulted in the NRC issuing three orders effective on March 12, 2012 requiring U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating costs associated with operating Entergy’s nuclear plants, some of which could be material.

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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 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, or any interim storage facility, 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 expressed its intention and taken specific steps to discontinue the Yucca Mountain project and study a new spent fuel strategy. 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 the companies’ nuclear sites. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the 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 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

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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, 2012, the maximum assessment amounts total $81.4 million for the Utility plants and $93.4 million for the Entergy Wholesale Commodities plants. Retrospective Premium Insurance available through NEIL’s reinsurance treaty can cover the potential assessments. The Entergy Wholesale Commodities 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.

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. In addition, the former owner of Indian Point 3 and FitzPatrick retained the decommissioning trusts and related liability to decommission these plants, but has the right to require the respective Entergy

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Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assigns the funds in the corresponding decommissioning trust, up to a specified level, to such owners. Alternatively, the former owner may contract with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the transferred funds mentioned above. 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 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.

Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.

NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants. Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies’, System Energy’s and owners of the Entergy Wholesale Commodities’ nuclear power plants. Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. 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 shutdown 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 effect on Entergy’s results of operations, financial condition, and liquidity.

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(Entergy Corporation)

A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities nuclear power plants could have a material 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 Indian Point 2 and Indian Point 3 expire in September 2013 and December 2015, respectively. Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined. 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.

In relation to Indian Point 2 and Indian Point 3, the New York State 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 ensure that requirements of the Coastal Zone Management Act, which is administered in New York State primarily by the New York Department of State, are satisfied (to the extent required) prior to getting the renewed licenses. For further information regarding these environmental regulations see “Entergy Wholesale Commodities – Property – Nuclear Generating Stations” in Part I, Item 1.

The NRC operating license for Vermont Yankee was to expire in March 2012. In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years, as a result of which the license now expires in 2032. Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that expired in March 2012, but has an application pending before the Vermont Public Service Board for a new Certificate of Public Good for operation until March 2032, and continues to operate the plant pursuant to federal court order, the absence of any order to cease operation, and its position that Vermont’s law extends a license’s expiration date when a timely and sufficient renewal application has been filed. For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.

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 is able to prevent the continued operation of such plant, Entergy’s results of operations, financial condition, and liquidity could be materially 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 the “Entergy Wholesale Commodities – Property – Nuclear Generating Stations” section in Part I, Item 1.

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 or a site-specific estimate, 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

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power plants. 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 projected costs do 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 or site-specific estimate 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 Indian Point 2 and Palisades, the total amount in each of those trusts as of December 31, 2012 would not have been sufficient to initiate and complete the immediate near-term radiological decommissioning of the respective unit as of the license termination date of each respective plant, 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 decides to shut down and immediately begin decommissioning one of those nuclear power plants on its license expiration date, its trust funds for the plant as of December 31, 2012 would have been insufficient and the applicable Entergy subsidiary would have been required to rely on other capital resources to fund the remainder of the radiological 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). If any Entergy subsidiary decides to shut down one of its 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 affected.

Entergy Wholesale Commodities’ nuclear power plants are exposed to price risk.

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. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2012, Entergy Wholesale Commodities nuclear power generation plants had sold forward 85%, 73%, 39%, 25% and 26% of its generation portfolio’s planned energy output for 2013, 2014, 2015, 2016, and 2017, respectively.

Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend 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. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.

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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 various products including 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. See the “Results of Operations, Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. With operating licenses for Indian Point 2 and Indian Point 3 expiring in 2013 and 2015, respectively, and as a consequence of any 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.

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;

·	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 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 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;

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·	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);

·	changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; 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 Entergy 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 business 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 the “Regulation of Entergy’s Business” section in Part I, Item 1.

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

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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 affected.

The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition or liquidity.

Entergy 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 are subject to impairment if adverse market conditions arise and continue (such as expected long-term 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 in the “Entergy Wholesale Commodities - Property” section in Part I, Item 1, the operating licenses for Indian Point 2 and Indian Point 3 expire in 2013 and 2015, respectively, and are currently the subject of license renewal processes at the NRC and the state in which the plants operate, and the Vermont Yankee plant is the subject of certain state and federal proceedings and federal litigation relating to continued operation of that plant. As discussed in Note 1 to the financial statements, Entergy recognized an impairment charge for the Vermont Yankee plant in 2012. In addition, 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 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 effect on Entergy’s results of operations, financial condition, or liquidity.

General Business

(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’s 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 and Entergy Wholesale Commodities. 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, Hurricane Gustav and Hurricane Ike in 2008, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or

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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 debt 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 each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. 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.

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, 2012, based on power prices at that time, Entergy had liquidity exposure for Entergy Wholesale Commodities business transactions of $203 million under guarantees, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs. As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements could increase by $106 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, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.

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The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially 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, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, 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 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, greenhouse gases, and other regulated air emissions 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 and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.

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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), the SERC Reliability Corporation (SERC), and other regional enforcement entities, 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 and generation assets. 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 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 effect on the Utility operating companies’ financial condition, results of operations, and liquidity.

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. In addition, a number of Entergy’s larger industrial customers have the ability to develop cogeneration facilities that would enable them to greatly eliminate or reduce their purchases of electricity from Entergy. It is possible that continued or recurrent poor economic conditions or the departure of one or more large customers to cogeneration could result in slower or declining sales growth and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.

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The effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or to place a price on greenhouse gas emissions could materially 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. In 2012, EPA proposed a CO2 emission standard for new sources; this standard is expected to be finalized in 2013. Additionally, EPA is expected to develop a proposed CO2 emission standard for existing power generation facilities perhaps as early as 2013. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative (RGGI) establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. Developing and implementing plans for compliance with greenhouse gas 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; moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. Violations of such requirements may subject Entergy Wholesale Commodities 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, 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 affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, multiple lawsuits currently are pending or are reasonably expected 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, wind and storm surge damages, 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. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.

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 effect on Entergy’s, Entergy Wholesale Commodities’, and the Utility operating companies’ financial condition, results of operations, and liquidity.

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Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and Entergy Wholesale Commodities’ business.

Water is a vital natural resource that also is critical to the Utility operating companies, System Energy, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Two of Entergy’s Utility operating companies own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.

Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.

Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.

To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, 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 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 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 all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to

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perform, Entergy or its subsidiaries may enforce and recover the proceeds from 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 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 Wall Street Reform and Consumer Protection Act, and the rules and regulations promulgated under the act 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 are subject to mandatory clearing and exchange trading requirements. Swap dealers and major market participants in the swap market are subject to capital, margin, registration, reporting, recordkeeping, and business conduct requirements with respect to their swap activities. Position limits may also apply to certain swaps activities. Non-swap dealers and non-major market participants, which Entergy expects to qualify as, are subject to reporting, recordkeeping, and business conduct requirements (i.e. anti-manipulation, anti-disruptive trading practices, and whistleblower provisions) with respect to their swap activities. Position limit rules promulgated by the Commodity Futures Trading Commission were vacated by the US District Court for the District of Columbia. In response, the Commodity Futures Trading Commission has announced it will appeal the court’s decision. If the Commodity Futures Trading Commission’s appeal is successful, position limits may apply to certain of Entergy’s swaps activities. The act required 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 has been largely completed. Both the Utility operating companies 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, the imposition of position limits, 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 may 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. Volatility in the capital markets has 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. For further information regarding Entergy’s pension and other postretirement benefit plans, refer 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.

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Part I Item 1A & 1B

Entergy Corporation, Utility operating companies, and System Energy

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. The 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, including cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ technology systems 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 that affects its ability to operate, or an act against the information technology systems and network infrastructure of Entergy and its subsidiaries.

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, failures or breaches were to occur, Entergy’s and the Utility operating companies’ business, financial condition, and results of operations could be materially affected. The risk of such attacks, failures, or breaches 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 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, refer to Note 3 to the financial statements.

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Part I Item 1A & 1B

Entergy Corporation, Utility operating companies, and System Energy

Entergy and the Utility operating companies may be unable to satisfy the conditions or obtain the approvals to complete the transaction with ITC or such approvals may contain material restrictions or conditions.

See “Plan to Spin Off the Utility’s Transmission Business” in Entergy Corporation’s Management’s Financial Discussion and Analysis for a discussion of the agreements that Entergy entered in December 2011 to spin off its transmission business and merge it with a newly-formed subsidiary of ITC Holdings Corp. The consummation of the ITC transaction is subject to numerous conditions, including (i) consummation of certain transactions and financings contemplated by the Merger Agreement and the Separation Agreement (such as the separation of the Transmission Business conducted by the Utility operating companies, (ii) obtaining the required ITC shareholder approvals, and (iii) the receipt of certain regulatory approvals from governmental agencies necessary to consummate the ITC transaction, and that no such regulatory approvals impose a burdensome condition on ITC or Entergy as described in the Merger Agreement. Entergy can make no assurances that the ITC transaction will be consummated on the terms or timeline currently contemplated, or at all. Governmental agencies may not approve the ITC transaction or may impose conditions to the approval of the ITC transaction or require changes to the terms of the ITC transaction. Any such conditions or changes could have the effect of delaying completion of the ITC transaction, imposing costs on or limiting the revenues of Entergy or the Utility operating companies, or otherwise reducing the anticipated benefits of the ITC transaction. Any condition or change could result in a burdensome condition on the Transmission Business, the Utility operating companies, or ITC under the Merger Agreement and might cause Entergy or ITC to abandon the ITC transaction. In addition, Entergy must pay its costs related to the ITC transaction including, legal, accounting, advisory, financing and filing fees, and printing costs, whether the ITC transaction is completed or not. Any failure to consummate the ITC transaction as currently contemplated, or at all, could have a material effect on the business and results of operations of Entergy and the Utility operating companies and the trading price of Entergy Corporation’s common stock could be adversely affected.

(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’s results of operations and liquidity.

Gas rates charged to retail gas 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 monthly, 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’s 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 which could adversely affect results of operations.

(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. 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 filed in October 2011 an application with the NRC for an extension of Grand Gulf’s operating license to 2045. 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.

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Part I Item 1A & 1B

Entergy Corporation, Utility operating companies, and System Energy

For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other 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 “Sale and Leaseback Transactions” section of Note 10 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, see the “Retained Earnings and Dividend Restrictions” section of Note 7 to the financial statements.

If completed, the transaction with ITC may not achieve its anticipated results.

Entergy entered into the ITC transaction with the expectation that it would result in various benefits, including the receipt by Entergy’s shareholders of shares of ITC common stock as a result of the transaction. If the ITC transaction is consummated, it is possible that the full strategic, financial, operational, and regulatory benefits to Entergy and its shareholders that Entergy expected would result from the ITC transaction may not be achieved or that such benefits may be delayed or not occur due to unforeseen changes in market, economic or regulatory conditions or other events. As a result, the aggregate market price of the common stock of Entergy Corporation and the shares of ITC common stock that shareholders of Entergy Corporation would receive in the ITC transaction could be less than the market price of Entergy Corporation’s common stock if the ITC transaction had not occurred.

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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Plan to Spin Off the Utility’s Transmission Business

See the “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp., including the planned retirement of debt and preferred securities.

Results of Operations

Net Income

2012 Compared to 2011

Net income decreased $12.5 million primarily due to higher other operation and maintenance expenses and higher taxes other than income taxes, partially offset by a lower effective income tax rate.

2011 Compared to 2010

Net income decreased $7.7 million primarily due to a higher effective income tax rate, lower other income, and higher other operation and maintenance expenses, partially offset by higher net revenue, lower depreciation and amortization expenses, and lower interest expense.

Net Revenue

2012 Compared to 2011

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 credits. Following is an analysis of the change in net revenue comparing 2012 to 2011.

	Amount
	(In Millions)

2011 net revenue	$	1,252.3
Retail electric price		23.4
Net wholesale revenue		5.7
Transmission revenue		(9.6	)
Volume/weather		(19.0	)
Other		0.2
2012 net revenue	$	1,253.0

The retail electric price variance is primarily due to an increase in the energy efficiency rider, as approved by the APSC, effective July 2012. The energy efficiency rider revenues are offset by costs included in other operation and maintenance expenses and have no effect on net income.

The net wholesale revenue variance is primarily due to higher wholesale billings to affiliate companies due to higher expenses and lower wholesale energy costs.

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Management’s Financial Discussion and Analysis

The transmission revenue variance is primarily due to a revision to transmission investment equalization billings under the System Agreement among the Utility operating companies (for the approximate period of 1996 – 2011) recorded in the fourth quarter 2011.

The volume/weather variance is primarily due to the effects of milder weather, as compared to the prior period, primarily on residential sales.

Gross operating revenues, fuel and purchased power expenses, and other regulatory credits

Gross operating revenues increased primarily due to an increase of $39.2 million in rider revenues related to higher System Agreement production cost equalization payments and an increase of $16.1 million in rider revenues due to an increase in the energy efficiency rider effective July 2012. The increase was partially offset by the June 2012 refund to AmerenUE of $30.6 million, including interest, of rough production cost equalization payments collected from AmerenUE. Entergy Arkansas had previously recorded a regulatory provision for the potential refund to AmerenUE. The result of the refund is a decrease in gross revenues with an offsetting increase in other regulatory credits. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” in Note 2 to the financial statements for a discussion of the FERC order in the System Agreement production cost equalization proceedings.

Fuel and purchased power expenses increased primarily due to an increase in the recovery from customers of deferred fuel costs, partially offset by a decrease in the average market price of purchased power.

Other regulatory credits increased primarily due to the June 2012 refund to AmerenUE, as discussed above.

2011 Compared to 2010

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 2011 to 2010.

	Amount
	(In Millions)

2010 net revenue	$	1,216.7
Retail electric price		31.0
ANO decommissioning trust		26.4
Transmission revenue		13.1
Capacity acquisition recovery		(10.3	)
Net wholesale revenue		(11.9	)
Volume/weather		(15.9	)
Other		3.2
2011 net revenue	$	1,252.3

The retail electric price variance is primarily due to a base rate increase effective July 2010. See Note 2 to the financial statements for more discussion of the rate case settlement.

The ANO decommissioning trust variance is primarily related to the deferral of investment gains from the ANO 1 and 2 decommissioning trust in 2010 in accordance with regulatory treatment. The gains resulted in an increase in 2010 in interest and investment income and a corresponding increase in regulatory charges with no effect on net income.

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Management’s Financial Discussion and Analysis

The capacity acquisition recovery variance is primarily due to the cessation of the capacity acquisition rider to recover expenses incurred because those costs are recovered in base rates effective July 2010.

The net wholesale revenue variance is primarily due to lower margins on co-owner contracts and lower wholesale billings to affiliate companies due to lower expenses.

The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales, partially offset by more favorable weather-adjusted usage in the residential sector.

Other Income Statement Variances

2012 Compared to 2011

Other operation and maintenance expenses increased primarily due to:

an increase of $14.8 million in compensation and benefits costs resulting from a decrease in the discount rate and changes in certain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

·	an increase of $13.9 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have no effect on net income;

·	$13.3 million of costs incurred in 2012 related to the planned spin-off and merger of the Utility’s transmission business; and

·	an increase of $10.3 million in nuclear generation expenses primarily due to higher contract costs.

The increase was partially offset by a decrease of $8.0 million in fossil-fueled generation expenses primarily due to higher plant outage costs in 2011 due to a greater scope of work.

Nuclear refueling outage expenses increased primarily due to higher costs associated with the most recent outage as compared to the previous outages.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes resulting from higher assessments and an increase in local franchise taxes resulting from higher residential and commercial electric revenues compared to 2011. Franchise taxes have no effect on net income as these taxes are recovered through the franchise tax rider.

2011 Compared to 2010

Other operation and maintenance expenses increased primarily due to:

·	an increase of $6.1 million in fossil-fueled generation costs due to higher fossil plant outage costs due to a greater scope of work in 2011;

·	an increase of $3.9 million in transmission and distribution maintenance work in 2011;

·	$3.5 million in contract costs due to the transition and implementation of joining the MISO RTO; and

·	an increase of $3 million in nuclear expenses primarily due to higher labor and contract costs caused by several factors.

The increase was offset by a $7.5 million decrease in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense.

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.

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Management’s Financial Discussion and Analysis

Other income decreased primarily due to the investment gains on the ANO 1 and 2 decommissioning trust in 2010, as discussed above in net revenue, and the carrying charges on storm restoration costs recorded in 2010 related to the January 2009 ice storm. See Note 2 to the financial statements for further discussion of the 2009 ice storm costs and Note 5 to the financial statements for a discussion of the August 2010 issuance of securitization bonds to finance these costs.

Interest expense decreased primarily due to the refinancing of debt at lower interest rates.

Income Taxes

The effective income tax rates for 2012, 2011, and 2010 were 38.4%. 44.6%, and 39.6%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.

	2012			2011			2010
	(In Thousands)

Cash and cash equivalents at beginning of period	$	22,599		$	106,102		$	86,233

Net cash provided by (used in):
Operating activities		509,117			564,124			512,260
Investing activities		(723,248	)		(503,524	)		(413,180	)
Financing activities		226,065			(144,103	)		(79,211	)
Net increase (decrease) in cash and cash equivalents		11,934			(83,503	)		19,869

Cash and cash equivalents at end of period	$	34,533		$	22,599		$	106,102

Operating Activities

Net cash provided by operating activities decreased $55.0 million in 2012 compared to 2011 primarily due to the $156 million System Agreement bandwidth remedy payment made in January 2012 as a result of the payment required to implement the FERC’s remedy for the period June – December 2005, a decrease of $69.5 million in income tax refunds, and the $30.6 million refund, including interest, to AmerenUE, as discussed above. These decreases were partially offset by a decrease of $83.2 million in pension contributions and the increased recovery of fuel and purchased power costs, including partial recovery of the System Agreement bandwidth remedy payment made in January 2012. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.

Net cash provided by operating activities increased $51.9 million in 2011 compared to 2010 primarily due to income tax refunds of $90 million in 2011 compared to income tax payments of $66.4 million in 2010. In 2011, Entergy Arkansas received tax cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds result from a decrease in 2010 taxable income from what was previously estimated because of the recognition of additional repair expenses for tax purposes associated with a tax accounting change filed in 2010 and from the reversal of temporary differences for which Entergy Arkansas previously made cash tax payments. Pension contributions decreased $16.6 million. See “Critical Accounting Estimates” below for a discussion of qualified pension and other postretirement benefits funding. The increase was offset by under-recovery of fuel costs and $19 million in storm restoration spending resulting from the April 2011 storms which caused damage to Entergy Arkansas’s transmission and distribution lines, equipment poles, and other facilities.

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Management’s Financial Discussion and Analysis

Investing Activities

Net cash used in investing activities increased $219.7 million in 2012 compared to 2011 primarily due to the purchase of Hot Spring Energy Facility for approximately $253 million in November 2012 and money pool activity. The increase was partially offset by fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. See Note 15 to the financial statements for a discussion of the purchase of Hot Spring Energy Facility.

Decreases in Entergy Arkansas’s receivable from the money pool are a source of cash flow, and Entergy Arkansas’s receivable from the money pool decreased by $9.3 million in 2012 compared to decreasing by $24.1 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash used in investing activities increased $90.3 million in 2011 compared to 2010 primarily due to:

an increase of $66.3 million in nuclear fuel purchases primarily due to the purchase of nuclear fuel inventory from System Fuels because the Utility companies will now purchase nuclear fuel throughout the nuclear fuel procurement cycle, rather than purchasing it from System Fuels at the time of refueling; and

·	$51 million in storm restoration spending resulting from the April 2011 storms which caused damage to Entergy Arkansas’s transmission and distribution lines, equipment poles, and other facilities; and

·	$30 million in transmission substation reliability work in 2011.

The increase was partially offset by money pool activity.

Increases in Entergy Arkansas’s receivable from the money pool are a use of cash flow, and Entergy Arkansas’s receivable from the money pool increased by $12.6 million in 2010.

Financing Activities

Financing activities provided cash of $226.1 million in 2012 compared to using cash of $144.1 million in 2011 primarily due to:

the issuance of $200 million of 4.9% Series first mortgage bonds in December 2012 and $60 million 2.62% Series K note by the nuclear fuel company variable interest entity in December 2012 compared to the issuance of $55 million 3.23% Series J note by the nuclear fuel company variable interest entity in June 2011;

·	a decrease of $107.8 million in common stock dividends paid in 2012;

·	the repayment, at maturity, of a $35 million 5.60% Series G note by the nuclear fuel company variable interest entity in September 2011; and

·	an increase in borrowings on the nuclear fuel company variable interest entity’s credit facility.

Net cash used in financing activities increased $64.9 million in 2011 compared to 2010 primarily due to:

the issuance of $575 million of first mortgage bonds by Entergy Arkansas and $124.1 million of storm cost recovery bonds by Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, in 2010 compared to the issuance of the $55 million Series J note by the nuclear fuel company variable interest entity in 2011; and

·	a decrease in borrowings on the nuclear fuel company variable interest entity’s credit facility.

The increase was offset by:

·	the retirement of $450 million of first mortgage bonds and $139.5 million of pollution control revenue bonds in 2010 compared to the retirement of the $35 million Series G note by the nuclear fuel company variable interest entity in 2011; and

·	a decrease of $55.6 million in common stock dividends paid in 2011.

See Note 5 to the financial statements for details of long-term debt.

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Entergy Arkansas, Inc. and Subsidiaries

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, 2012	December 31, 2011

Debt to capital	56.0%	55.0%
Effect of excluding the securitization bonds	(1.2%)	(1.5%)
Debt to capital, excluding securitization bonds (1)	54.8%	53.5%
Effect of subtracting cash	(0.4%)	(0.3%)
Net debt to net capital, excluding securitization bonds (1)	54.4%	53.2%

(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 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 or retirements;

·	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.

	2013	2014-2015	2016-2017	after 2017	Total
	(In Millions)
Planned construction and capital investment (1):
Generation	$102	$344	N/A	N/A	$446
Transmission	93	303	N/A	N/A	396
Distribution	146	281	N/A	N/A	427
Other	43	88	N/A	N/A	131
Total	$384	$1,016	N/A	N/A	$1,400
Long-term debt (2)	$416	$216	$310	$2,529	$3,471
Capital lease payments	$0.2	$0.4	$-	$-	$0.6
Operating leases	$28	$55	$20	$4	$107
Purchase obligations (3)	$684	$1,175	$549	$1,858	$4,266

(1)

Includes approximately $252 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. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development.

(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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Management’s Financial Discussion and Analysis

In addition, Entergy Arkansas currently expects to contribute approximately $34.9 million to its pension plans and approximately $26.7 million to other postretirement plans in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy Arkansas has $2.5 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 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 indenture restricts 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, 2012, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million.

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, redeem, or otherwise retire 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 the money pool were as follows as of December 31 for each of the following years.

2012	2011	2010	2009
(In Thousands)

$8,035	$17,362	$41,463	$28,859

See Note 4 to the financial statements for a description of the money pool.

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Entergy Arkansas has credit facilities in the amount of $20 million and $150 million scheduled to expire in April 2013 and March 2017, respectively. No borrowings were outstanding under the credit facilities as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $85 million scheduled to expire in July 2013. As of December 31, 2012, $36.7 million was outstanding on the credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Arkansas has obtained short-term borrowing authorization from the FERC under which it may borrow through October 2013, 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 2015. Entergy Arkansas has also obtained long-term financing authorization from the FERC that extends through May 2013 for issuances by its nuclear fuel company variable interest entity.

In January 2013, Entergy Arkansas arranged for the issuance by (i) Independence County, Arkansas of $45 million of 2.375% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due January 2021, and (ii) Jefferson County, Arkansas of $54.7 million of 1.55% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due October 2017, each of which series is secured by a separate series of non-interest bearing first mortgage bonds of Entergy Arkansas. The proceeds of these issuances were applied to the refunding of outstanding series of pollution control revenue bonds previously issued by the respective issuers.

State and Local Rate Regulation and Fuel-Cost Recovery

Retail Rates

2009 Base Rate Filing

2013 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.

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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 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 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.

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 decide the case based on the record in the proceeding, including the prefiled testimony.

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.

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Entergy Arkansas December 2012 Winter Storm

In December 2012, a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm are estimated to be in the range of $55 million to $65 million. Entergy Arkansas recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Arkansas recorded corresponding regulatory assets of approximately $21 million and construction work in progress of approximately $37 million. Entergy Arkansas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Arkansas has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Arkansas is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery. Entergy Arkansas plans to present a cost recovery proposal to the APSC in a base rate case filing in March 2013.

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.

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 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. 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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Federal Regulation

See “Independent Coordinator of Transmission”, “System Agreement”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, 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.

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.

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After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.

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.

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 Financial 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.

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 and meet certain eligibility requirements 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

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employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial 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 and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Qualified Pension Cost	Impact on Qualified Projected Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$3,461	$44,172
Rate of return on plan assets	(0.25%)	$1,934	$-
Rate of increase in compensation	0.25%	$1,369	$7,694

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$1,118	$11,528
Health care cost trend	0.25%	$1,690	$9,971

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 2012 was $53.1 million. Entergy Arkansas anticipates 2013 qualified pension cost to be approximately $63 million. Entergy Arkansas’s contributions to the pension trust were $37.2 million in 2012 and are currently estimated to be approximately $34.9 million in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.

Total postretirement health care and life insurance benefit costs for Entergy Arkansas in 2012 were $18.1 million, including $5.8 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas expects 2013 postretirement health care and life insurance benefit costs to approximate $14.1 million, including $6.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas contributed $24.4 million to its other postretirement plans in 2012 and expects to contribute approximately $26.7 million in 2013.

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 Financial Discussion and Analysis for further discussion.

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ENTERGY GULF STATES LOUISIANA, L.L.C.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Plan to Spin Off the Utility’s Transmission Business

See the “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of this matter, including the planned retirement of debt and preferred securities.

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Gulf States Louisiana’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Gulf States Louisiana’s electric facilities damaged by Hurricane Isaac are currently estimated to be approximately $70 million. Entergy Gulf States Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. In January 2013, Entergy Gulf States Louisiana drew $65 million from its funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.

Entergy Gulf States Louisiana recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Gulf States Louisiana recorded corresponding regulatory assets of approximately $17 million and construction work in progress of approximately $53 million. Entergy Gulf States Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Gulf States Louisiana has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Gulf States Louisiana is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.

Results of Operations

Net Income

2012 Compared to 2011

Net income decreased $42.6 million primarily due to lower net revenue and higher other operation and maintenance expenses. These items were partially offset by the $19.8 million income tax savings resulting from an IRS settlement in June 2012 related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing, which also resulted in a $27.7 million ($17 million net-of-tax) regulatory charge that reduced net revenue because the savings will be shared with customers. See Note 3 to the financial statements for additional discussion of the tax settlement and savings obligation.

2011 Compared to 2010

Net income increased $27.3 million primarily due to lower interest expense, a lower effective income tax rate, and lower other operation and maintenance expenses, offset by higher depreciation and amortization expenses.

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Net Revenue

2012 Compared to 2011

	Amount
	(In Millions)

2011 net revenue	$	933.4
Louisiana Act 55 financing savings obligation		(26.7	)
Retail electric price		(12.0	)
Volume/weather		(7.9	)
Net wholesale revenue		(7.8	)
Transmission revenue		(7.2	)
Other		(5.9	)
2012 net revenue	$	865.9

The Louisiana Act 55 financing savings obligation results from a regulatory charge recorded in 2012 because Entergy Gulf States Louisiana is sharing the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing with customers. See Note 3 to the financial statements for additional discussion of the tax settlement and savings obligation.

The retail electric price variance is primarily due to increased affiliate purchased power capacity costs recovered through base rates set in the annual formula rate plan mechanism. See Note 2 to the financial statements for additional discussion of Entergy Gulf States Louisiana’s formula rate plan.

The volume/weather variance is primarily due to the effect of milder weather, as compared to the prior period, on residential and commercial sales and the effects of the power outages caused by Hurricane Isaac.

The net wholesale revenue variance is primarily due to decreased sales volume to municipal and co-op customers and lower prices.

Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)

Gross operating revenues decreased primarily due to a decrease of $203.8 million in gross wholesale revenues primarily due to a decrease in sales to affiliated customers, a decrease of $168.4 million in fuel cost recovery revenues primarily due to lower fuel rates, and a decrease of $59.3 million in rider revenues primarily due to higher System Agreement credits in 2012. See Note 2 to the financial statements for additional discussion of Entergy Gulf States Louisiana’s fuel and purchased power recovery mechanism.

Fuel and purchased power expenses decreased primarily due to:

·	a decrease in the average market prices of purchased power and natural gas; and

·	a decrease in deferred fuel expense due to the timing of receipt of System Agreement payments and credits to customers and lower fuel cost recovery revenues in 2012. See Note 2 to the financial statements for a discussion of the System Agreement proceedings.

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Other regulatory charges increased primarily due to a settlement with the IRS related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers. See Note 3 to the financial statements for additional discussion of the settlement and savings obligation.

2011 Compared to 2010

	Amount
	(In Millions)

2010 net revenue	$	933.6
Retail electric price		(20.1	)
Volume/weather		(5.2	)
Transmission revenue		12.4
Fuel recovery		14.8
Other		(2.1	)
2011 net revenue	$	933.4

The retail electric price variance is primarily due to an increase in credits passed on to customers as a result of the Act 55 storm cost financing. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.

The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, including during the unbilled sales period. The decrease was partially offset by an increase of 62 GWh, or 0.3%, in billed electricity usage, primarily due to increased consumption by an industrial customer as a result of the customer’s cogeneration outage and the addition of a new production unit by the industrial customer.

The fuel recovery variance resulted primarily from an adjustment to deferred fuel costs in 2010. See Note 2 to the financial statements for a discussion of fuel recovery.

Fuel and purchased power expenses

Fuel and purchased power expenses increased primarily due to:

·	an increase in deferred fuel expense due to the timing of receipt of System Agreement payments and credits to customers;

·	an increase in natural gas fuel expense primarily due to increased generation; and

·	an increase in deferred fuel expense due to fuel and purchased power expense decreases in excess of lower fuel cost recovery revenues.

The increase was offset by a decrease in the average market price of purchased power and decreased net area demand.

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Management’s Financial Discussion and Analysis

Other Income Statement Variances

2012 Compared to 2011

Other operation and maintenance expenses increased primarily due to:

·	an increase of $10.4 million in nuclear generation expenses primarily due to higher labor costs, including higher contract labor;

an increase of $9.3 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;

·	$4.7 million of costs incurred in 2012 related to the planned spin-off and merger of the transmission business; and

·	an increase of $3.7 million in fossil-fueled generation expenses resulting primarily from increased plant outages and an increased scope of work as compared to the prior year.

The increase was partially offset by:

·	$5.8 million of transmission investment equalization expenses recorded in the fourth quarter 2011 as a result of a billing adjustment related to prior transmissions costs (for the approximate period of 1996 – 2011) allocable to Entergy Gulf States Louisiana under the System Agreement;

·	the deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $4.2 million; and

·	several individually insignificant items.

2011 Compared to 2010

Nuclear refueling outage expenses decreased primarily due to the amortization of lower expenses associated with the planned maintenance and refueling outage at River Bend in the first quarter 2011.

Other operation and maintenance expenses decreased primarily due to:

·	a decrease of $6 million in fossil-fueled generation expenses primarily due to fewer outages and a reduced scope of work compared to 2010; and

·	a decrease of $4.2 million in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense.

The decrease was partially offset by an increase of $2.9 million in costs due to the transition and implementation of joining the MISO RTO, as well as several individually insignificant items.

Depreciation and amortization expenses increased primarily due to a revision in the second quarter 2010 related to depreciation on storm cost-related assets and an increase in plant in service. Recovery of the storm cost-related assets will now be through the Act 55 financing of storm costs as approved by the LPSC in June 2010. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.

Interest expense decreased primarily due to:

·	redemptions of first mortgage bonds of $68 million in June 2010 and $304 million in November 2010, partially offset by the issuance of first mortgage bonds of $250 million in October 2010. See Note 5 to the financial statements for a discussion of long-term debt; and

·	interest expense accrued in 2010 related to the expected result of the LPSC Staff audit of the fuel adjustment clause for the period 1995 through 2004. See Note 2 to the financial statements for a discussion of fuel recovery.

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Management’s Financial Discussion and Analysis

Income Taxes

The effective income tax rates were 24.9%, 30.8%, and 34.6% for 2012, 2011, and 2010, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Correction of Regulatory Asset for Income Taxes

See Note 2 to the financial statements for a discussion of the financial statement effects of a correction to Entergy Gulf States Louisiana’s regulatory asset for income taxes.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.

	2012			2011			2010
	(In Thousands)

Cash and cash equivalents at beginning of period	$	24,845		$	155,173		$	144,460

Net cash provided by (used in):
Operating activities		346,208			482,115			726,130
Investing activities		(201,440	)		(267,262	)		(541,583	)
Financing activities		(133,927	)		(345,181	)		(173,834	)
Net increase (decrease) in cash and cash equivalents		10,841			(130,328	)		10,713

Cash and cash equivalents at end of period	$	35,686		$	24,845		$	155,173

Operating Activities

Net cash provided by operating activities decreased $135.9 million in 2012 compared to 2011 primarily due to income tax payments in 2012 of $89.2 million in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement compared to income tax refunds of $56.3 million in 2011. In 2012, Entergy Gulf States Louisiana no longer had a net operating loss carryover from prior years to reduce current taxable income. Also contributing to the decrease in cash flow was Hurricane Isaac storm restoration spending in 2012. In 2011, Entergy Gulf States Louisiana received tax cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds resulted from the reversal of temporary differences for which Entergy Gulf States Louisiana previously made cash tax payments.

The decrease was partially offset by:

an increase in the recovery of fuel and purchased power costs due to System Agreement bandwidth remedy payments of $75 million received in January 2012 as a result of receipts required to implement the FERC’s remedy in an October 2011 order for the period June – December 2005. In the fourth quarter 2012, Entergy Gulf States Louisiana customers were credited $69.6 million. See Note 2 to the financial statements for a discussion of the System Agreement proceedings; and

·	a decrease of $13.7 million in pension contributions. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits.

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Net cash provided by operating activities decreased $244 million in 2011 compared to 2010 primarily due to:

·	proceeds of $240.3 million received from the LURC as a result of the Act 55 storm cost financings in 2010. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; and

·	higher nuclear refueling outage spending at River Bend. River Bend had a refueling outage in 2011 and did not have one in 2010.

The decrease was partially offset by an increase in income tax refunds of $39.5 million in 2011 compared to 2010. In 2011, Entergy Gulf States Louisiana received tax cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds resulted from the reversal of temporary differences for which Entergy Gulf States Louisiana previously made cash tax payments.

Investing Activities

Net cash used in investing activities decreased $65.8 million in 2012 compared to 2011 primarily due to:

·	fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle;

·	$51 million in proceeds from the sale of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests to a third party in 2012; and

·	a decrease in nuclear construction expenditures as a result of the River Bend refueling outage in 2011. River Bend had a refueling outage in 2011 and did not have one in 2012.

The decrease was partially offset by:

·	higher distribution construction expenditures due to Hurricane Isaac and increased reliability work performed in 2012;

·	money pool activity;

·	an increase in fossil-fueled generation construction expenditures due to an increased scope of work in 2012; and

·	an increase in transmission construction expenditures due to increased transmission plant upgrades in 2012.

Decreases in Entergy Gulf States Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Gulf States Louisiana’s receivable from the money pool decreased by $23.6 million in 2012 compared to decreasing by $39.4 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce the Utility operating companies’ need for external short-term borrowings.

Net cash used in investing activities decreased $274.3 million in 2011 compared to 2010 primarily due to:

the investment in 2010 of $150.3 million in affiliate securities and the investment of $90.1 million in the storm reserve escrow account as a result of the Act 55 storm cost financings. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; and

·	money pool activity.

The decrease was partially offset by an increase in nuclear fuel purchases because River Bend had a refueling outage in 2011 and did not have one in 2010.

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Financing Activities

Net cash used in financing activities decreased $211.3 million in 2012 compared to 2011 primarily due to a decrease of $187.8 million in common equity distributions and the issuance of $75 million 3.25% Series Q notes by the nuclear fuel company variable interest entity in July 2012, partially offset by:

·	the repayment, at maturity, of $60 million 5.41% Series O notes by the nuclear fuel company variable interest entity in July 2012;

·	the redemption of $10.84 million of pollution control revenue bonds in 2012 compared to the redemption of $47.34 million of pollution control revenue bonds in 2011; and

·	payments of $29.4 million on credit borrowings in 2012 compared to an increase of $5.2 million in credit borrowings in 2011 against the nuclear fuel company variable interest entity credit facility.

Net cash used in financing activities increased $171.3 million in 2011 compared to 2010 primarily due to an increase of $177.7 million in common equity distributions.

Capital Structure

Entergy Gulf States Louisiana’s capitalization is balanced between equity and debt, as shown in the following table.

	December 31, 2012	December 31, 2011

Debt to capital	52.3%	53.6%
Effect of subtracting cash	(0.6%)	(0.4%)
Net debt to net capital	51.7%	53.2%

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and long-term debt, including the currently maturing portion. Capital consists of debt and member’s equity. Net capital consists of capital less cash and cash equivalents. Entergy Gulf States Louisiana 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 Gulf States Louisiana’s financial condition.

Uses of Capital

Entergy Gulf States Louisiana requires capital resources for:

·	construction and other capital investments;

·	debt and preferred equity maturities or retirements;

·	working capital purposes, including the financing of fuel and purchased power costs; and

·	distribution and interest payments.

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Following are the amounts of Entergy Gulf States Louisiana’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations.

	2013	2014-2015	2016-2017	after 2017	Total
	(In Millions)
Planned construction and capital investment (1):
Generation	$79	$154	N/A	N/A	$233
Transmission	83	99	N/A	N/A	182
Distribution	76	138	N/A	N/A	214
Other	20	44	N/A	N/A	64
Total	$258	$435	N/A	N/A	$693
Long-term debt (2)	$153	$191	$237	$1,851	$2,432
Operating leases	$12	$30	$18	$44	$104
Purchase obligations (3)	$169	$289	$187	$197	$842

(1)	Includes approximately $146 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. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development.
(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 Gulf States Louisiana, it primarily includes unconditional fuel and purchased power obligations.

In addition to the contractual obligations given above, Entergy Gulf States Louisiana expects to contribute $11.2 million to its pension plans and $8.4 million to other postretirement plans in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.

Also, in addition to the contractual obligations, Entergy Gulf States Louisiana has $304.8 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 Gulf States Louisiana 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, and the ability to access capital.

Management provides more information on long-term debt maturities in Note 5 to the financial statements.

As an indirect, wholly-owned subsidiary of Entergy Corporation, Entergy Gulf States Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Gulf States Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.

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New Nuclear Development

Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In the first quarter 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and recognized on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Utility Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company’s current participation level in the project.

In March 2010, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. The testimony and legal briefs of the LPSC staff generally support the request of Entergy Gulf States Louisiana and Entergy Louisiana, although other parties filed briefs, without supporting testimony, in opposition to the request. At an evidentiary hearing in October 2011, Entergy Gulf States Louisiana, Entergy Louisiana, and the LPSC staff presented testimony in support of certification of activities to preserve an option for a new nuclear plant at River Bend. The ALJ recommended, however, that the LPSC decline the request of Entergy Gulf States Louisiana and Entergy Louisiana on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. There has been no suggestion that the planning activities or costs incurred were imprudent. At its June 28, 2012 meeting the LPSC voted to uphold the ALJ’s decision and directed that Entergy Gulf States Louisiana and Entergy Louisiana be permitted to seek recovery of these costs in their anticipated, upcoming rate case filings, fully reserving the LPSC’s right to determine the recoverability of such costs in rates. On September 10, 2012, Entergy Gulf States Louisiana and Entergy Louisiana filed a petition for appeal and judicial review of the LPSC’s order with the Louisiana Nineteenth Judicial District Court. A schedule for the appeal has not been established. In their rate cases filed in February 2013, Entergy Gulf States Louisiana and Entergy Louisiana request recovery of their new nuclear generation development costs over a ten-year amortization period, with the costs included in rate base.

Sources of Capital

Entergy Gulf States Louisiana’s sources to meet its capital requirements include:

·	internally generated funds;

·	cash on hand;

·	debt or preferred membership interest issuances; and

·	bank financing under new or existing facilities.

Entergy Gulf States Louisiana may refinance, redeem, or otherwise retire debt and preferred equity/membership interests prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred equity/membership interest issuances by Entergy Gulf States Louisiana require prior regulatory approval. Preferred equity/membership interest and debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Gulf States Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Gulf States Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2012	2011	2010	2009
(In Thousands)

($7,074)	$23,596	$63,003	$50,131

See Note 4 to the financial statements for a description of the money pool.

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Entergy Gulf States Louisiana has a credit facility in the amount of $150 million scheduled to expire in March 2017. No borrowings were outstanding under the credit facility as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Gulf States Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $85 million scheduled to expire in July 2013. No borrowings were outstanding on the variable interest entity credit facility as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facilities.

Entergy Gulf States Louisiana obtained short-term borrowing authorization from the FERC under which it may borrow through October 2013, up to the aggregate amount, at any one time outstanding, of $200 million. See Note 4 to the financial statements for further discussion of Entergy Gulf States Louisiana’s short-term borrowing limits. Entergy Gulf States Louisiana has also obtained an order from the FERC authorizing long-term securities issuances through July 2013. Entergy Gulf States Louisiana has also obtained long-term financing authorization from the FERC that extends through September 2014 for issuances by its nuclear fuel company variable interest entity.

In February 2013 the Entergy Gulf States Louisiana nuclear fuel company variable interest entity issued $70 million of 3.38% Series R notes due August 2020. The Entergy Gulf States Louisiana nuclear fuel company variable interest entity used the proceeds principally to purchase additional nuclear fuel.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Gulf States Louisiana’s service territory. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. In October 2008, Entergy Gulf States Louisiana drew all of its $85 million funded storm reserve. On October 15, 2008, the LPSC approved Entergy Gulf States Louisiana’s request to defer and accrue carrying costs on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate.

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.

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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 $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. In the first quarter 2012, Entergy Gulf States Louisiana sold to a third party for $51 million a portion of its investment in Entergy Holdings Company’s Class A preferred membership interests.

Entergy Gulf States Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LCDA, and there is no recourse against Entergy Gulf States Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy Gulf States Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.

Entergy Louisiana’s Ninemile Point Unit 6 Self-Build Project

In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 will be a nominally-sized 550 MW unit that is estimated to cost approximately $721 million to construct, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 35% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is proposed to be allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor. All major permits and approvals required to begin construction have been obtained and construction is in progress.

Under the terms approved by the LPSC, costs may be recovered through Entergy Louisiana’s and Entergy Gulf States Louisiana’s formula rate plans, if one is in effect when the project is placed in service; alternatively, Entergy Gulf States Louisiana and Entergy Louisiana must file rate cases approximately 12 months prior to the expected in-service date.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Gulf States Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Gulf States Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC is primarily responsible for approval of the rates charged to customers.

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Retail Rates – Electric

In October 2009, the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the 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.

In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implemented effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.

In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflected an 11.11% earned 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 also reflected a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.

In November 2011, the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate decrease was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The

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revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.

·	authorization to increase the revenue it collects from customers by approximately $28 million;

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement;

·	authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and,

·	authorization to increase the revenue it collects from customers by approximately $24 million;

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Retail Rates – Gas

In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18 %, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.

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Fuel and purchased power cost recovery

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 included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.

In December 2011, the LPSC authorized its staff to initiate another 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 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.

Industrial and Commercial Customers

Entergy Gulf States Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States Louisiana’s industrial customer base. Entergy Gulf States Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Gulf States Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Gulf States Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States Louisiana’s marketing efforts in retaining industrial customers.

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Federal Regulation

See “Independent Coordinator of Transmission”, “System Agreement”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.

Nuclear Matters

Entergy Gulf States Louisiana owns and, through an affiliate, operates the River Bend nuclear power plant. Entergy Gulf States Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. 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 River Bend, Entergy Gulf States Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

Environmental Risks

Entergy Gulf States Louisiana’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 Gulf States Louisiana 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.

Critical Accounting Estimates

The preparation of Entergy Gulf States Louisiana’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’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 Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

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Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Gulf States Louisiana 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.

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 and meet certain eligibility requirements 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 Financial 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 and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Qualified Pension Cost	Impact on Qualified Projected Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$1,808	$23,290
Rate of return on plan assets	(0.25%)	$1,011	$-
Rate of increase in compensation	0.25%	$708	$4,256

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$876	$8,042
Health care cost trend	0.25%	$1,322	$7,509

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for Entergy Gulf States Louisiana in 2012 was $19.8 million. Entergy Gulf States Louisiana anticipates 2013 qualified pension cost to be $29.8 million. Entergy Gulf States Louisiana contributed $13.6 million to its pension plans in 2012 and estimates 2013 pension contributions to be approximately $11.2 million; although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.

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Total postretirement health care and life insurance benefit costs for Entergy Gulf States Louisiana in 2012 were $21.3 million, including $3.7 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Gulf States Louisiana expects 2013 postretirement health care and life insurance benefit costs to approximate $20.8 million, including $3.9 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Gulf States Louisiana contributed $7.6 million to its other postretirement plans in 2012 and expects to contribute approximately $8.4 million in 2013.

Federal Healthcare Legislation

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of

Entergy Gulf States Louisiana, L.L.C.

Baton Rouge, Louisiana

We have audited the accompanying balance sheets of Entergy Gulf States Louisiana, L.L.C. (the “Company”) as of December 31, 2012 and 2011, and the related income statements, statements of comprehensive income, statements of cash flows, and statements of changes in equity (pages 309 through 314 and applicable items in pages 57 through 204) for each of the three years in the period ended December 31, 2012. 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 financial statements present fairly, in all material respects, the financial position of Entergy Gulf States Louisiana, L.L.C. as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 27, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Plan to Spin Off the Utility’s Transmission Business

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Isaac are currently estimated to be approximately $220 million. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. In January 2013, Entergy Louisiana drew all of its $187 million funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.

Entergy Louisiana recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded corresponding regulatory assets of approximately $76 million and construction work in progress of approximately $144 million. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.

Results of Operations

Net Income

2012 Compared to 2011

Net income decreased $192.8 million primarily due to a prior year settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a $422 million reduction in income tax expense in the third quarter 2011. The net income effect was partially offset by a $199 million regulatory charge, which reduced net revenue in 2011 because Entergy Louisiana is sharing the benefit with customers. Partially offsetting the decrease in net income was an IRS tax settlement, in second quarter 2012, related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing, which resulted in a $142.7 million income tax savings, partially offset by a $137.1 million ($84.3 million net-of-tax) regulatory charge, which reduced net revenue in 2012 because Entergy Louisiana is sharing the savings with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlements and savings obligation.

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Management’s Financial Discussion and Analysis

2011 Compared to 2010

Net income increased $242.5 million primarily due to a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a $422 million income tax benefit. The net income effect was partially offset by a $199 million regulatory charge, which reduced net revenue, because a portion of the benefit will be shared with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.

Net Revenue

2012 Compared to 2011

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 2012 to 2011.

	Amount
	(In Millions)

2011 net revenue	$	886.2
Mark-to-market tax settlement sharing		199.5
Retail electric price		6.7
Volume/weather		(21.4	)
Louisiana Act 55 financing savings obligation		(134.1	)
Other		(3.6	)
2012 net revenue	$	933.3

The mark-to-market tax settlement sharing variance results from a regulatory charge recorded in the third quarter 2011 because Entergy Louisiana is sharing the benefits of a settlement with the IRS related to mark-to-market income tax treatment of power purchase contracts with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.

The retail electric price variance is primarily due to a special formula rate plan increase effective May 2011 in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. See Note 2 to the financial statements for discussion of the formula rate plan increase.

The volume/weather variance is primarily due to the effect of milder weather as compared to the previous year on residential and commercial sales and the effects of the power outages caused by Hurricane Isaac, partially offset by increased usage in the industrial sector as a result of increased consumption by a large industrial customer in the chemical industry as a result of plant expansion.

The Louisiana Act 55 financing savings obligation sharing variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Louisiana is sharing the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financings with customers. See Note 3 to the financial statements for additional discussion of the settlement and savings obligation.

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Gross operating revenues, fuel and purchased power expenses, and other regulatory charges

Gross operating revenues decreased primarily due to:

·	a decrease of $330.3 million in fuel cost recovery revenues primarily due to lower fuel rates. Entergy Louisiana’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements;

·	a decrease of $42 million in rider revenues primarily due to higher System Agreement credits in 2012; and

·	the decrease related to volume/weather, as discussed above.

Fuel and purchased power expenses decreased primarily due to a decrease in the average market prices of natural gas and purchased power and a decrease in the recovery from customers of deferred fuel costs.

Other regulatory charges decreased primarily due to a regulatory charge recorded in the third quarter 2011 because Entergy Louisiana is sharing the benefits of a settlement with the IRS related to mark-to-market income tax treatment of power purchase contracts with customers, partially offset by a regulatory charge recorded in the second quarter 2012 because Entergy Louisiana is sharing the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlements and savings obligation.

2011 Compared to 2010

	Amount
	(In Millions)

2010 net revenue	$	1,043.7
Mark-to-market tax settlement sharing		(195.9	)
Volume/weather		11.6
Retail electric price		32.5
Other		(5.7	)
2011 net revenue	$	886.2

The mark-to-market tax settlement sharing variance results from a regulatory charge recorded in the third quarter 2011 because a portion of the benefits of a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts will be shared with customers, slightly offset by the amortization of a portion of that charge beginning in October 2011. See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.

The volume/weather variance is primarily due to an increase of 1,095 GWh, or 4%, in billed electricity usage. Usage in the industrial sector increased primarily as a result of increased consumption by a large customer in the chemical industry as the result of a plant expansion. The increase was partially offset by the effect of less favorable weather on residential sales.

The retail electric price variance is primarily due to a formula rate plan increase effective May 2011. See Note 2 to the financial statements for discussion of the formula rate plan increase.

Other regulatory charges (credits)

Other regulatory charges increased primarily due to a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts because a portion of the settlement will be shared with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.

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Other Income Statement Variances

2012 Compared to 2011

Other operation and maintenance expenses decreased primarily due to:

·	$17.1 million of transmission investment equalization expenses recorded in the fourth quarter 2011 as a result of a billing adjustment related to prior transmission costs (for the approximate period of 1996-2011) allocable to Entergy Louisiana under the System Agreement;

·	a decrease of $7.3 million in fossil-fueled generation expenses due to an overall lower scope of outages compared to prior year;

·	the deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $5.2 million; and

·	a decrease of $2.7 million as a result of lower write-offs of uncollectible accounts in 2012.

The decrease was partially offset by:

an increase of $11.2 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs; and

·	$6.7 million of costs incurred in 2012 related to the planned spin-off and merger of the transmission business.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the acquisition of the Acadia Unit 2 in April 2011.

Interest expense increased primarily due to:

·	cessation in 2011 of interest on transmission credits per a FERC order relating to an interconnection and operating agreement between a power producer and Entergy Louisiana;

·	the issuance of $200 million of 4.8% Series first mortgage bonds in March 2011;

·	the issuance by Entergy Louisiana Investment Recovery Funding, L.L.C., a wholly owned subsidiary of Entergy Louisiana, of $207.2 million of senior secured investment recovery bonds with a coupon rate of 2.04% in September 2011;

·	the issuance of $250 million of 1.875% Series first mortgage bonds in January 2012; and

·	the issuance of $200 million of 5.25% Series first mortgage bonds in July 2012.

2011 Compared to 2010

Other operation and maintenance expenses increased primarily due to an increase of $17.1 million in transmission investment equalization expenses as a result of a billing adjustment recorded in the fourth quarter 2011 related to prior transmission costs (for the approximate period of 1996-2011) allocable to Entergy Louisiana under the System Agreement and an increase of $17.5 million in fossil-fueled generation expenses due to an overall higher scope of outages compared to prior year and the addition of Acadia Unit 2 in April 2011.

Other income increased primarily due to an increase of $10.8 million in distributions earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received from the Act 55 storm cost financing and an increase in the allowance for equity funds used during construction due to more construction work in progress in 2011. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.

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Management’s Financial Discussion and Analysis

Income Taxes

The effective income tax rates for 2012, 2011, and 2010 were (84.7%), (357.0%), and 22.3%, respectively. The effective income tax rate of (84.7%) for 2012 was primarily due to the settlement of the tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs and the reversal of the provision for the uncertain tax positions related to that item. The decline in the rate for 2011 is primarily due to the reversal in the third quarter 2011 for uncertain tax positions resulting from a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates and for a discussion of the IRS settlement and audits.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.

	2012			2011			2010
	(In Thousands)

Cash and cash equivalents at beginning of period	$	878		$	123,254		$	151,849

Net cash provided by (used in):
Operating activities		447,698			479,342			932,334
Investing activities		(850,866	)		(811,203	)		(861,329	)
Financing activities		432,376			209,485			(99,600	)
Net increase (decrease) in cash and cash equivalents		29,208			(122,376	)		(28,595	)

Cash and cash equivalents at end of period	$	30,086		$	878		$	123,254

Operating Activities

Net cash provided by operating activities decreased $31.6 million in 2012 primarily due to decreased recovery of fuel costs due to a lower fuel rate for the period, Hurricane Isaac storm restoration spending in 2012, and an increase of $22.9 million in interest paid resulting from the increase in interest expense, as discussed above. The decrease was partially offset by a decrease of $31.8 million in pension contributions and the purchase in 2011 of $28.1 million of fuel oil from System Fuels because System Fuels will no longer procure fuel oil for the Utility companies. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits.

Net cash provided by operating activities decreased $453 million in 2011 primarily due to proceeds of $462 million received in 2010 from the LURC as a result of the Act 55 storm cost financings. The decrease was partially offset by income tax refunds of $39.6 million in 2011 compared to income tax payments of $28.3 million in 2010. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the storm cost financings. In 2011, Entergy Louisiana received tax cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds primarily result from a decrease in 2010 taxable income from what was previously estimated because of the recognition of additional repair expenses for tax purposes associated with a tax accounting change filed in 2010.

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Investing Activities

Net cash used in investing activities increased $39.7 million in 2012 primarily due to:

·	an increase in fossil construction expenditures due to spending on the Ninemile Unit 6 self-build project;

·	an increase in nuclear construction expenditures due to the Waterford 3 steam generator replacement project in 2012. The increase is partially offset by various nuclear projects in 2011;

·	higher distribution construction expenditures due to Hurricane Isaac; and

·	money pool activity.

The increase was partially offset by:

·	the purchase of the Acadia Unit 2 for approximately $300 million in April 2011;

·	a decrease in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle;

·	a decrease in transmission construction expenditures due to increased work performed in 2011; and

·	receipts of $13.7 million in 2012 from the storm reserve escrow account.

Increases in Entergy Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Louisiana’s receivable from the money pool increased by $9.4 million in 2012 compared to decreasing by $49.9 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash used in investing activities decreased $50.1 million in 2011 primarily due to:

the investment in 2010 of $262.4 million in affiliate securities and the investment of $200 million in the storm reserve escrow account as a result of the Act 55 storm cost financings. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; and

·	money pool activity.

The increase was partially offset by:

·	the purchase of the Acadia Power Plant for approximately $300 million in April 2011; and

an increase in nuclear fuel activity because of the timing of refueling outages and the purchase of nuclear fuel inventory from System Fuels because the Utility companies will now purchase nuclear fuel throughout the nuclear fuel procurement cycle, rather than purchasing it from System Fuels at the time of refueling.

Decreases in Entergy Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased by $49.9 million in 2011 compared to decreasing by $2.9 million in 2010.

Financing Activities

Net cash provided by financing activities increased $222.9 million in 2012 primarily due to:

·	net cash issuances of $650 million of first mortgage bonds in 2012 compared to net cash issuances of $200 million of first mortgage bonds in 2011;

·	a decrease of $342.6 million in common equity dividends in 2012;

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·	the issuance by Entergy Louisiana Investment Recovery Funding, L.L.C., a wholly owned subsidiary of Entergy Louisiana, of $207.2 million of senior secured investment recovery bonds with a coupon rate of 2.04% in September 2011;

·	the issuance of the $25 million 3.25% Series G note by the nuclear fuel company variable interest entity in August 2012;

·	the issuance of the $20 million 3.30% Series F note by the nuclear fuel company variable interest entity in March 2011;

·	a principal payment of $25.6 million in 2012 for the Senior Secured Investment Recovery bonds;

·	an increase in borrowings of $10.3 million on the nuclear fuel company variable interest entity’s credit facility in 2012 compared to an increase in borrowings of $21.3 million on the nuclear fuel company variable interest entity’s credit facility in 2011;

·	a principal payment of $25.3 million in 2012 for the Waterford 3 sale-leaseback obligation compared to a principal payment of $35.5 million in 2011;

·	borrowing of $50 million on Entergy Louisiana’s credit facility in 2011 and the payment on the credit borrowing of $50 million in 2012; and

·	money pool activity.

Decrease in Entergy Louisiana's payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased by $118.4 million in 2012 compared to increasing by $118.4 million in 2011.

Entergy Louisiana’s financing activities provided cash of $209.5 million in 2011 compared to using cash of $99.6 million in 2010 primarily due to:

·	the issuance by Entergy Louisiana Investment Recovery Funding, L.L.C., a wholly owned subsidiary of Entergy Louisiana, of $207.2 million of senior secured investment recovery bonds with a coupon of 2.04% in September 2011;

·	net cash issuances of $200 million of first mortgage bonds in 2011 compared to net cash redemptions of $120 million of first mortgage bonds in 2010;

·	an increase in borrowings on the nuclear fuel company variable interest entity’s credit facility;

·	borrowings of $50 million on its credit facility in 2011;

·	the retirement of the $30 million Series D note by the nuclear fuel company variable interest entity in January 2010;

·	the issuance of the $20 million Series F note by the nuclear fuel company variable interest entity in March 2011;

·	money pool activity;

·	common equity dividends of $358.2 million paid in 2011;

·	the issuance in October 2010 of $115 million of 5% Revenue Bonds Series 2010; and

·	a principal payment of $35.5 million in 2011 for the Waterford 3 sale-leaseback obligation compared to a principal payment of $17.3 million in 2010.

Increases in Entergy Louisiana’s payable to the money pool are a source of cash flow, and Entergy Louisiana’s payable to the money pool increased by $118.4 million in 2011.

See Note 5 to the financial statements for details of long-term debt.

Capital Structure

Entergy Louisiana’s capitalization is balanced between equity and debt, as shown in the following table.

	December 31, 2012	December 31, 2011

Debt to capital	48.4%	47.2%
Effect of excluding securitization bonds	(1.6%)	(2.3%)
Debt to capital, excluding securitization bonds (1)	46.8%	44.9%
Effect of subtracting cash	(0.3%)	-%
Net debt to net capital, excluding securitization bonds (1)	46.5%	44.9%

(1)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana.

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Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and long-term debt, including the currently maturing portion. Capital consists of debt and members’ equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana 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 Louisiana’s financial condition.

Uses of Capital

Entergy Louisiana requires capital resources for:

·	construction and other capital investments;

·	debt and preferred equity maturities or retirements;

·	working capital purposes, including the financing of fuel and purchased power costs; and

·	distribution and interest payments.

Following are the amounts of Entergy Louisiana’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations.

	2013	2014-2015	2016-2017	After 2017	Total
	(In Millions)
Planned construction and capital investment (1):
Generation	$530	$306	N/A	N/A	$836
Transmission	117	201	N/A	N/A	318
Distribution	130	233	N/A	N/A	363
Other	19	79	N/A	N/A	98
Total	$796	$819	N/A	N/A	$1,615
Long-term debt (2)	$152	$603	$404	$3,689	$4,848
Operating leases	$11	$18	$8	$4	$41
Purchase obligations (3)	$600	$1,150	$975	$5,981	$8,706

(1)	Includes approximately $207 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. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development.
(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 Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements.

In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $20.7 million to its pension plans and approximately $10.2 million to other postretirement plans in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.

The planned capital investment estimate for Entergy Louisiana reflects capital required to support existing business and customer growth, including the Ninemile 6 self-build project and final spending from the Waterford 3 steam generator replacement project, both of which are discussed below. 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, and the ability to access capital.

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Management provides more information on long-term debt maturities in Note 5 to the financial statements.

As an indirect, wholly-owned subsidiary of Entergy Corporation, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.

Waterford 3 Steam Generator Replacement Project

Entergy Louisiana planned to replace the Waterford 3 steam generators, along with the reactor vessel closure head and control element drive mechanisms, in the spring 2011. Replacement of these components is common to pressurized water reactors throughout the nuclear industry. In December 2010, Entergy Louisiana advised the LPSC that the replacement generators would not be completed and delivered by the manufacturer in time to install them during the spring 2011 refueling outage. During the final steps in the manufacturing process, the manufacturer discovered separation of stainless steel cladding from the carbon steel base metal in the channel head of both replacement steam generators (RSGs), in areas beneath and adjacent to the divider plate. As a result of this damage, the manufacturer was unable to meet the contractual delivery deadlines, and the RSGs were not installed in the spring 2011. Waterford 3 resumed operations with the original steam generators upon completion of the spring 2011 refueling outage, which included inspection and maintenance of the original steam generators.

Entergy Louisiana worked with the RSG manufacturer to fully develop, evaluate, and implement repair options, and the RSGs were delivered in time for Waterford 3’s fall 2012 refueling outage, which began in October 2012. During the fall 2012 refueling outage Entergy Louisiana replaced the RSGs, reactor vessel head, and control element drive mechanisms. Those components, which together comprised the replacement project, were placed in-service in December 2012.

In June 2008, Entergy Louisiana filed with the LPSC for approval of the replacement project, including full cost recovery. Following discovery and the filing of testimony by the LPSC staff and an intervenor, the parties entered into a stipulated settlement of the proceeding. The LPSC unanimously approved the settlement in November 2008. The settlement resolved the following issues: 1) the accelerated degradation of the steam generators is not the result of any imprudence on the part of Entergy Louisiana; 2) the decision to undertake the replacement project at the then-estimated cost is in the public interest, is prudent, and would serve the public convenience and necessity; 3) the scope of the replacement project is in the public interest; 4) undertaking the replacement project at the target installation date during the 2011 refueling outage is in the public interest; and 5) the jurisdictional costs determined to be prudent in a future prudence review are eligible for cost recovery, either in an extension or renewal of the formula rate plan or in a full base rate case including necessary pro forma adjustments.

In November 2011, the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan and provided a mechanism to begin recovering the costs of the replacement project in the first billing cycle after it is placed in service. On December 21, 2012, Entergy Louisiana provided notice of the first year revenue requirement associated with the replacement project that would be placed into rates in the January 2013 billing cycle. The estimated revenue requirement included the LPSC-jurisdictional share of the replacement project costs, less (i) a credit for earnings above a 10.25% return on common equity (based on the 2011 test year) for the period following the in-service date, and (ii) a credit for operation and maintenance savings expected from the RSGs. These rates are anticipated to remain in effect until Entergy Louisiana’s rate case filed in February 2013 is resolved. See “State and Local Rate Regulation and Fuel-Cost Recovery” below for additional discussion of the formula rate plan and rate case filings. With completion of the replacement project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.

See “State and Local Rate Regulation and Fuel-Cost Recovery” below for a discussion of the renewal of Entergy Louisiana’s formula rate plan for the 2011 test year and its provisions addressing the Waterford 3 steam generator replacement project.

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Ninemile Point Unit 6 Self-Build Project

New Nuclear Development

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Sources of Capital

Entergy Louisiana’s sources to meet its capital requirements include:

·	internally generated funds;

·	cash on hand;

·	debt or preferred membership interest issuances; and

·	bank financing under new and existing facilities.

Entergy Louisiana may refinance, redeem, or otherwise retire debt and preferred membership interests prior to maturity, to the extent market conditions and interest and distribution rates are favorable.

All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Preferred membership interest and debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

2012	2011	2010	2009
(In Thousands)

$9,433	($118,415)	$49,887	$52,807

See Note 4 to the financial statements for a description of the money pool.

Entergy Louisiana has a credit facility in the amount of $200 million scheduled to expire in March 2017. No borrowings were outstanding under the facility as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $90 million scheduled to expire in July 2013. As of December 31, 2012, $54.7 million was outstanding on the credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Louisiana obtained short-term borrowing authorization from the FERC under which it may borrow through October 2013, up the aggregate amount, at any one time outstanding, of $250 million. See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits. Entergy Louisiana has also obtained an order from the FERC authorizing long-term securities issuances through July 2013. Entergy Louisiana has also obtained long-term financing authorization from the FERC that extends through January 2015 for issuances by its nuclear fuel company variable interest entity.

Little Gypsy Repowering Project

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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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 was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. 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 participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Louisiana to recover $200 million as of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011, Entergy Louisiana filed an application with the LPSC to authorize the securitization of the investment recovery costs associated with the project and to issue a financing order by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlement and also issued a financing order for the securitization. See Note 5 to the financial statements for a discussion of the September 2011 issuance of the securitization bonds.

Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav (and, to a much lesser extent, Hurricane Ike) caused catastrophic damage to Entergy Louisiana’s service territory. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. On October 9, 2008, Entergy Louisiana drew all of its $134 million funded storm reserve. On October 15, 2008, the LPSC approved Entergy Louisiana’s request to defer and accrue carrying costs on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm costs or final carrying costs rate.

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Management’s Financial Discussion and Analysis

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.

Entergy Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.

In May 2005 the LPSC approved a rate filing 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. As discussed below the formula rate plan has been extended, with return on common equity provisions consistent with previously approved provisions, to cover the 2008, 2009, 2010, and 2011 test years.

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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Management’s Financial Discussion and Analysis

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.

In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s current formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.

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Management’s Financial Discussion and Analysis

·	authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement;

·	authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and,

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

·	authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);

·	an authorized return on common equity of 10.4%;

·	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

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. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1.0 million from Entergy Louisiana's fuel adjustment clause to base rates. Two parties have intervened in the proceeding. A procedural schedule has not yet been established. Entergy Louisiana has recorded provisions for the estimated outcome of this proceeding.

Industrial and Commercial Customers

Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Louisiana’s marketing efforts in retaining industrial customers.

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Federal Regulation

Nuclear Matters

Entergy Louisiana owns and, through an affiliate, operates the Waterford 3 nuclear power plant. Entergy Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. 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 Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

Environmental Risks

Entergy Louisiana’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 Louisiana 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.

Critical Accounting Estimates

The preparation of Entergy Louisiana’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 Louisiana’s financial position or results of operations.

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Nuclear Decommissioning Costs

In the second quarter 2012, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement obligation asset that will be depreciated over the remaining life of the unit.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Louisiana 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.

Qualified Pension and Other Postretirement Benefits

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Qualified Pension Cost	Impact on Projected Qualified Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$2,368	$29,843
Rate of return on plan assets	(0.25%)	$1,201	$-
Rate of increase in compensation	0.25%	$968	$5,869

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Management’s Financial Discussion and Analysis

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$897	$8,198
Health care cost trend	0.25%	$1,304	$7,321

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for Entergy Louisiana in 2012 was $37.4 million. Entergy Louisiana anticipates 2013 qualified pension cost to be $45.1 million. Entergy Louisiana contributed $28.8 million to its pension plans in 2012 and anticipates funding approximately $20.7 million in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.

Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2012 were $22.1 million, including $3.6 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Louisiana expects 2013 postretirement health care and life insurance benefit costs to approximate $23 million, including $4 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Louisiana contributed $11 million to its other postretirement plans in 2012 and expects to contribute approximately $10.2 million in 2013.

Federal Healthcare Legislation

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of

Entergy Louisiana, LLC and Subsidiaries

Baton Rouge, Louisiana

We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2012 and 2011 and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of cash flows, and consolidated statements of changes in equity (pages 335 through 340 and applicable items in pages 57 through 204) for each of the three years in the period ended December 31, 2012. 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.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, LLC and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 27, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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ENTERGY TEXAS, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Plan to Spin Off the Utility’s Transmission Business

Results of Operations

Net Income

2012 Compared to 2011

Net income decreased $38.9 million primarily due to lower net revenue, higher other operation and maintenance expenses, higher depreciation and amortization expenses, and lower other income, partially offset by lower taxes other than income taxes.

2011 Compared to 2010

Net income increased $14.6 million primarily due to higher net revenue, partially offset by higher taxes other than income taxes, higher other operation and maintenance expenses, and higher depreciation and amortization expenses.

Net Revenue

2012 Compared to 2011

	Amount
	(In Millions)

2011 net revenue	$	577.8
Volume/weather		(22.7	)
Purchased power capacity		(20.1	)
Fuel recovery		(6.5	)
Retail electric price		15.1
Reserve equalization		20.2
Other		(12.8	)
2012 net revenue	$	551.0

The volume/weather variance is primarily due to a decrease of 519 GWh, or 3.1%, in billed electricity usage, including the effect of milder weather compared to last year on residential and commercial sales.

The purchased power capacity variance is primarily due to additional capacity purchases as well as price increases for ongoing purchased power capacity.

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The fuel recovery variance is primarily the result of a $6 million adjustment to deferred fuel costs in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.

The retail electric price variance is primarily due to rate actions, including an annual base rate increase of $9 million beginning May 2011 as a result of the settlement of the December 2009 rate case and an annual base rate increase of $28 million, effective July 2012, as a result of the PUCT’s order in the December 2011 rate case. See Note 2 to the financial statements for further discussion of the rate cases.

The reserve equalization variance is primarily due to decreased reserve equalization expense as a result of changes in the Entergy System generation mix compared to the same period in 2011.

Gross operating revenues, fuel and purchased power expenses, and other regulatory charges

Gross operating revenues decreased primarily due to:

a decrease of $156.2 million in fuel cost recovery revenues primarily attributable to lower fuel rates and lower usage, offset by lower interim fuel refunds in 2012 versus 2011. Entergy Texas’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements. The interim fuel refunds and the PUCT approvals are discussed in Note 2 to the financial statements; and

·	less favorable volume/weather, as discussed above.

The decrease was partially offset by an increase of $12.2 million in gross wholesale revenues as a result of an increase in sales to affiliated customers, offset by a decrease in sales volume to municipal and co-op customers.

Fuel and purchased power expenses decreased primarily due to decreases in the average market prices of natural gas and purchased power, partially offset by an increase in deferred fuel expense. The increase in deferred fuel expense is due to an adjustment to deferred fuel costs in accordance with a rate order from the PUCT issued in September 2012 and as a result of lower interim fuel refunds in 2012 versus 2011, offset by lower fuel revenues, as discussed above. See Note 2 to the financial statements for further discussion of the PUCT rate order.

Other regulatory charges increased primarily due to the distribution in the first quarter 2011 of $17.4 million to customers of the 2007 rough production cost equalization remedy receipts. See Note 2 to the financial statements for further discussion of the rough production cost equalization proceedings.

2011 Compared to 2010

	Amount
	(In Millions)

2010 net revenue	$	540.2
Retail electric price		36.0
Volume/weather		21.3
Purchased power capacity		(24.6	)
Other		4.9
2011 net revenue	$	577.8

The retail electric price variance is primarily due to rate actions, including an annual base rate increase of $59 million beginning August 2010, with an additional increase of $9 million beginning May 2011, as a result of the settlement of the December 2009 rate case. See Note 2 to the financial statements for further discussion of the rate case settlement.

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The volume/weather variance is primarily due to an increase of 721 GWh, or 4.5%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales compared to last year. Usage in the industrial sector increased 8.2% primarily in the chemicals and refining industries.

The purchased power capacity variance is primarily due to price increases for ongoing purchased power capacity and additional capacity purchases.

Gross operating revenues, fuel and purchased power expenses, and other regulatory charges

Gross operating revenues increased primarily due to the base rate increases and the volume/weather effect, as discussed above.

Fuel and purchased power expenses increased primarily due to an increase in demand coupled with an increase in deferred fuel expense as a result of lower fuel refunds in 2011 versus 2010, partially offset by a decrease in the average market price of natural gas.

Other regulatory charges decreased primarily due to the distribution in the first quarter 2011 of $17.4 million to customers of the 2007 rough production cost equalization remedy receipts. See Note 2 to the financial statements for further discussion of the rough production cost equalization proceedings.

Other Income Statement Variances

2012 Compared to 2011

Other operation and maintenance expenses increased primarily due to:

·	an increase of $7.2 million in fossil-fueled generation expenses due to a greater scope of work and an additional outage in 2012 compared to 2011;

·	$4.8 million of costs incurred in 2012 related to the planned spin-off and merger of the Utility’s transmission business;

·	the amortization of $4.3 million of Hurricane Rita storm costs in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order;

·	an increase of $3.5 million in compensation and benefit costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below for further discussion of benefits costs;

·	an increase of $2.7 million in loss reserves in 2012; and

·	an increase of $2.3 million in storm damage reserves in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.

The increase was partially offset by a decrease of $1.8 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have no effect on net income.

Taxes other than income taxes decreased primarily due to a reduction in the provision recorded for sales and use taxes.

Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in depreciation rates as a result of the rate order approved by the PUCT in September 2012. See Note 2 to the financial statements for further discussion of the rate order.

Other income decreased primarily due to the reversal of $6.7 million of disallowed carrying charges on Hurricane Rita storm restoration costs in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.

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2011 Compared to 2010

Other operation and maintenance expenses increased primarily due to:

·	an increase of $8.5 million in transmission expenses due to a billing adjustment recorded in the fourth quarter 2011 related to prior transmission investment equalization costs (for the approximate period of 1996 - 2011) allocable to Entergy Texas under the System Agreement;

·	an increase of $2.4 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have no effect on net income; and

·	several individually insignificant items.

The increase was partially offset by the amortization of $11 million of rate case expenses in 2010 and a decrease of $3.9 million in compensation and benefits costs primarily due to a decrease in stock option expense. See Note 2 to the financial statements for further discussion of the rate case settlement.

Taxes other than income taxes increased primarily due to an increase in local franchise taxes as a result of higher city franchise and gross receipts taxes and an increase in ad valorem taxes due to a higher 2011 assessment as compared to 2010, partially offset by lower street rentals.

Depreciation and amortization expenses increased primarily due to an increase in plant in service.

Income Taxes

The effective income tax rates were 44.1%, 38.0%, and 39.0% for 2012, 2011, and 2010, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.

	2012			2011			2010
	(In Thousands)

Cash and cash equivalents at beginning of period	$	65,289		$	35,342		$	200,703

Net cash provided by (used in):
Operating activities		271,081			238,837			43,095
Investing activities		(128,904	)		(219,783	)		(121,439	)
Financing activities		(147,230	)		10,893			(87,017	)
Net increase (decrease) in cash and cash equivalents		(5,053	)		29,947			(165,361	)

Cash and cash equivalents at end of period	$	60,236		$	65,289		$	35,342

Operating Activities

Net cash provided by operating activities increased $32.2 million in 2012 compared to 2011 primarily due to:

an increase in the recovery of fuel costs due to System Agreement bandwidth remedy payments of $43 million received in January 2012 as a result of receipts required to implement the FERC’s remedy in an October 2011 order for the period June-December 2005. In the fourth quarter 2012, Entergy Texas customers were credited $28.4 million. See Note 2 to the financial statements for a discussion of the System Agreement proceedings;

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·	a decrease of $9.1 million in pension contributions. See “Critical Accounting Estimates” below for a discussion of qualified pension and other postretirement benefits; and

·	$67.2 million of fuel cost refunds in 2012 compared to $73.4 million of fuel cost refunds in 2011. See Note 2 to the financial statements for discussion of the fuel cost refunds.

The increase was partially offset by a decrease of $11.3 million in income tax refunds.

Net cash provided by operating activities increased $195.7 million in 2011 compared to 2010 primarily due to:

·	$73.4 million of fuel cost refunds in 2011 versus $179.5 million of fuel cost refunds in 2010. See Note 2 to the financial statements for discussion of the fuel cost refunds; and

·	income tax refunds of $13.5 million in 2011 compared to income tax payments of $48.7 million in 2010.

Investing Activities

Net cash used in investing activities decreased $90.9 million in 2012 compared to 2011 primarily due to money pool activity, partially offset by higher fossil-fueled generation construction expenditures due to a greater scope of projects in 2012.

Decreases in Entergy Texas’s receivable from the money pool are a source of cash flow, and Entergy Texas’s receivable from the money pool decreased by $44 million in 2012 compared to increasing by $49.5 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce Entergy’s subsidiaries’ need for external short-term borrowings.

Net cash used in investing activities increased $98.3 million in 2011 compared to 2010 primarily due to money pool activity.

Increases in Entergy Texas’s receivable from the money pool are a use of cash flow, and Entergy Texas’s receivable from the money pool increased by $49.5 million in 2011 compared to decreasing by $55.6 million in 2010.

Financing Activities

Entergy Texas’s financing activities used $147.2 million in 2012 compared to providing $10.9 million in 2011 primarily due to an increase of $81.4 million in common stock dividends paid and the issuance of $75 million of 4.10% Series first mortgage bonds in September 2011.

Entergy Texas’s financing activities provided $10.9 million of cash in 2011 compared to using $87.0 million of cash in 2010 primarily due to:

·	the retirement of $199 million of debt assumption liabilities and securitization bonds in 2010 compared to the retirement of $57.4 million of securitization bonds in 2011; and

·	a decrease of $80.6 million in common equity distributions.

The cash provided was partially offset by the issuance of $200 million of 3.60% Series mortgage bonds in May 2010 compared to the issuance of $75 million of 4.10% Series first mortgage bonds in September 2011.

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Capital Structure

Entergy Texas’s capitalization is balanced between equity and debt, as shown in the following table.

	December 31, 2012	December 31, 2011

Debt to capital	65.4%	65.1%
Effect of excluding the securitization bonds	(13.3%)	(14.3%)
Debt to capital, excluding securitization bonds (1)	52.1%	50.8%
Effect of subtracting cash	(1.7%)	(1.9%)
Net debt to net capital, excluding securitization bonds (1)	50.4%	48.9%

(1)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas.

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Texas 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 Texas’s financial condition.

Uses of Capital

Entergy Texas requires capital resources for:

·	construction and other capital investments;

·	debt maturities or retirements;

·	working capital purposes, including the financing of fuel and purchased power costs; and

·	dividend and interest payments.

Following are the amounts of Entergy Texas’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations.

	2013	2014-2015	2016-2017	After 2017	Total
	(In Millions)
Planned construction and capital investment (1):
Generation	$76	$94	N/A	N/A	$170
Transmission	43	177	N/A	N/A	220
Distribution	75	146	N/A	N/A	221
Other	7	17	N/A	N/A	24
Total	$201	$434	N/A	N/A	$635
Long-term debt (2)	$88	$372	$253	$1,729	$2,442
Operating leases	$6	$9	$4	$2	$21
Purchase obligations (3)	$98	$126	$119	$247	$590

(1)	Includes approximately $124 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. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs.
(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 Texas, it primarily includes unconditional fuel and purchased power obligations.

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In addition to the contractual obligations given above, Entergy Texas expects to contribute approximately $6.7 million to its pension plans and approximately $5.2 million to other postretirement plans in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy Texas has $12.4 million of unrecognized tax benefits and interest net of unused tax attributes and payments 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.

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, and the ability to access capital. Management provides more information on long-term debt in Note 5 to the financial statements.

As a wholly-owned subsidiary, Entergy Texas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly.

Sources of Capital

Entergy Texas’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 Texas may refinance, redeem, or otherwise retire debt 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 Texas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Texas’s receivables from the money pool were as follows as of December 31 for each of the following years.

2012	2011	2010	2009
(In Thousands)

$19,175	$63,191	$13,672	$69,317

See Note 4 to the financial statements for a description of the money pool.

Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in March 2017. No borrowings were outstanding under the facility as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the credit facility.

Entergy Texas has obtained short-term borrowing authorization through October 2013 from the FERC under which it may borrow at any one time outstanding, $200 million in the aggregate. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits. Entergy Texas has also obtained an order from the FERC authorizing long-term securities issuances through July 2013.

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Management’s Financial Discussion and Analysis

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated and the rates charged to its customers are determined in regulatory proceedings. The PUCT, a governmental agency, is primarily responsible for approval of the rates charged to customers.

Filings with the PUCT

2009 Rate Case

The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided 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 stipulated an authorized return on equity of 10.125%. The settlement stated 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 set 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.

2011 Rate Case

In November 2011, Entergy Texas filed a rate requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.

In September 2012, the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s

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Management’s Financial Discussion and Analysis

Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.

Fuel and Purchased Power Cost Recovery

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 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 October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, over a three-month period to most customers beginning January 2013. The PUCT approved the stipulation in January 2013.

In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding. See Note 2 to the financial statements for a discussion of the FERC’s October 2011 order. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provides that most Entergy Texas customers will be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.

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Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Federal Regulation

Industrial and Commercial Customers

Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas responds by working with industrial and commercial customers and negotiating electric service contracts to provide, under existing rate schedules, competitive rates that match specific customer needs and load profiles. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Texas does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Texas’s marketing efforts in retaining industrial customers.

Environmental Risks

Entergy Texas’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 Texas 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.

Critical Accounting Estimates

The preparation of Entergy Texas’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 Texas’s financial position or results of operations.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy Texas 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 and fuel price fluctuations, in addition to changes in certain components of the calculation.

Qualified Pension and Other Postretirement Benefits

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Management’s Financial Discussion and Analysis

employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial 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 and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Qualified Pension Cost	Impact on Qualified Projected Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$940	$12,621
Rate of return on plan assets	(0.25%)	$657	$-
Rate of increase in compensation	0.25%	$372	$2,083

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).

Actuarial Assumption	Change in Assumption	Impact on 2012 Postretirement Benefit Cost	Impact on Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)

Discount rate	(0.25%)	$452	$5,005
Health care cost trend	0.25%	$775	$4,676

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for Entergy Texas in 2012 was $10.4 million. Entergy Texas anticipates 2013 qualified pension cost to be $14 million. Entergy Texas contributed $9.1 million to its qualified pension plans in 2012. Entergy Texas’s contributions to the pension trust are currently estimated to be approximately $6.7 million in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.

Total postretirement health care and life insurance benefit costs for Entergy Texas in 2012 were $6 million, including $1.3 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Texas expects 2013 postretirement health care and life insurance benefit costs to approximate $4.1 million, including $1.4 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Texas contributed $4.9 million to its other postretirement plans in 2012 and expects to contribute approximately $5.2 million in 2013.

Federal Healthcare Legislation

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Entergy Texas, Inc. and Subsidiaries

Beaumont, Texas

We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 390 through 394 and applicable items in pages 57 through 204) for each of the three years in the period ended December 31, 2012. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Texas, Inc. and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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 27, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

Item 2. Properties

Information regarding the registrant’s properties is included in Part I. Item 1. - Business under the sections titled “Utility - Property and Other Generation Resources” and “Entergy Wholesale Commodities - Property” in this report.

Item 3. Legal Proceedings

Details of the registrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 2012 are discussed in Part I. Item 1. - Business under the sections titled “Retail Rate Regulation”, “Environmental Regulation”, and “Litigation” and "Impairment of Long-Lived Assets" in Note 1 to the financial statements in this report.

Item 4. Mine Safety Disclosures

Not applicable.

EXECUTIVE OFFICERS OF ENTERGY CORPORATION

Executive Officers

Name	Age	Position	Period

Leo P. Denault (a)(b)	53	Chairman of the Board and Chief Executive Officer of Entergy Corporation	2013-Present
		Executive Vice President and Chief Financial Officer of Entergy Corporation	2004-2013
		Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and System Energy	2004-2013
		Director of Entergy Texas	2007-2013
		Director of Entergy New Orleans	2011-2013

J. Wayne Leonard (a)(b)	62	Chairman of the Board of Entergy Corporation	2006-2013
		Chief Executive Officer and Director of Entergy Corporation	1999-2013

William M. Mohl(a)(b)	53	President, Entergy Wholesale Commodity Business of Entergy Corporation	2013-Present
		President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana	2010-2013
		Director of Entergy Gulf States Louisiana and Entergy Louisiana	2010-2013
		Vice President, System Planning of Entergy Services, Inc.	2007-2010

Richard J. Smith (a)(b)	61	President, Entergy Wholesale Commodity Business of Entergy Corporation	2010-2013
		President and Chief Operating Officer of Entergy Corporation	2007-2010

Theodore H. Bunting, Jr. (a)	54	Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi and Entergy Texas	2012-Present
		Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas	2012-Present

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		Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and System Energy	2007-2012

Andrew S. Marsh (a)(b)	40	Executive Vice President and Chief Financial Officer of Entergy Corporation	2013-Present
		Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas and System Energy	2013-Present
		Vice President, System Planning of Entergy Services, Inc.	2010-2013
		Vice President, Planning and Financial Communications of Entergy Services, Inc.	2007-2010

Mark T. Savoff (a)	56	Executive Vice President and Chief Operating Officer of Entergy Corporation	2010-Present
		Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Mississippi	2004-Present
		Director of Entergy Texas	2007-Present
		Director of Entergy New Orleans	2011-Present
		Executive Vice President, Operations of Entergy Corporation	2004-2010

Roderick K. West (a)	44	Executive Vice President and Chief Administrative Officer of Entergy Corporation	2010-Present
		President and Chief Executive Officer of Entergy New Orleans	2007-2010
		Director of Entergy New Orleans	2005-2011

E. Renae Conley (a)	55	Executive Vice President, Human Resources and Administration of Entergy Corporation	2011-Present
		Executive Vice President of Entergy Corporation	2010-2011
		President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana	2000-2010
		Director of Entergy Gulf States Louisiana and Entergy Louisiana	2000-2010

Jeffrey S. Forbes(a)(c)	56	Executive Vice President, Nuclear Operations/Chief Nuclear Officer of Entergy Corporation	2013-Present
		Executive Vice President and Chief Nuclear Officer of Entergy Arkansas, Entergy Gulf States Louisiana and Entergy Louisiana	2013-Present
		President, Chief Executive Officer and Director of System Energy	2013-Present
		Senior Vice President, Nuclear Operations of Entergy Services, Inc.	2011-2013
		Senior Vice President and Chief Operating Officer of Entergy Operations, Inc.	2003-2011

John T. Herron (a)(c)	59	Nuclear Advisor	2013-Present
		President and Chief Executive Officer Nuclear Operations/ Chief Nuclear Officer of Entergy Corporation	2009-2013
		Executive Vice President and Chief Nuclear Officer of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Texas	2010-2013

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		President, Chief Executive Officer and Director of System Energy	2009-2013
		Senior Vice President, Nuclear Operations	2007-2009

Marcus V. Brown (a)	51	Senior Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and System Energy	2012-Present
		Vice President and Deputy General Counsel of Entergy Services, Inc.	2009-2012
		Associate General Counsel of Entergy Services, Inc.	2007-2009

Alyson M. Mount (a)	42	Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and System Energy	2012-Present
		Vice President Corporate Controller of Entergy Services, Inc.	2010-2012
		Director, Corporate Reporting and Accounting Policy of Entergy Services, Inc.	2002-2010

(a)	In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.
(b)	Mr. Leonard and Mr. Smith retired from the positions indicated effective January 31, 2013. Messrs. Denault, Marsh and Mohl assumed their new roles on February 1, 2013.
(c)	Mr. Herron resigned as President and Chief Executive Officer Nuclear Operations/Chief Nuclear Officer of Entergy Corporation effective January 2, 2013. He has advised Entergy that he intends to retire from his current position effective March 31, 2013.

Each officer of Entergy Corporation is elected yearly by the Board of Directors.

PART II

Item 5. Market for Registrants’ Common Equity and Related Stockholder Matters

Entergy Corporation

The shares of Entergy Corporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR.

The high and low prices of Entergy Corporation’s common stock for each quarterly period in 2012 and 2011 were as follows:

	2012		2011
	High	Low	High	Low
	(In Dollars)

First	73.66	66.23	74.50	64.72
Second	68.20	62.97	70.40	65.15
Third	74.50	67.07	69.14	57.60
Fourth	72.98	61.55	74.00	62.66

Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 2012 and 2011. Quarterly dividends of $0.83 per share were paid in 2012 and 2011.

As of January 31, 2013, there were 32,959 stockholders of record of Entergy Corporation.

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Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities (1)

Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of a Publicly Announced Plan	Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2)

10/01/2012-10/31/2012	-	$-	-	$350,052,918
11/01/2012-11/30/2012	-	$-	-	$350,052,918
12/01/2012-12/31/2012	-	$-	-	$350,052,918
Total	-	$-	-

In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In October 2010 the Board granted authority for an additional $500 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter 2012, Entergy withheld 20,110 shares of its common stock at $70.62 per share to pay taxes due upon vesting of restricted stock granted as part of its long-term incentive program.

(1)	See Note 12 to the financial statements for additional discussion of the stock-based compensation plans.
(2)	Maximum amount of shares that may yet be repurchased does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans.

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

There is no market for the common stock of Entergy Corporation’s wholly owned subsidiaries. Cash dividends on common stock paid by the Registrant Subsidiaries during 2012 and 2011, were as follows:

	2012	2011
	(In Millions)

Entergy Arkansas	$10.0	$117.8
Entergy Gulf States Louisiana	$114.2	$302.0
Entergy Louisiana	$15.6	$358.2
Entergy Mississippi	$-	$3.3
Entergy New Orleans	$1.7	$42.0
Entergy Texas	$87.2	$5.8
System Energy	$79.7	$76.0

Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends is presented in Note 7 to the financial statements.

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Item 6. Selected Financial Data

Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY GULF STATES LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.” which follow each company’s financial statements in this report, for information with respect to selected financial data and certain operating statistics.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY GULF STATES, LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.”

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments.”

Item 8. Financial Statements and Supplementary Data

Refer to “TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.”

Item 9. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure

No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As of December 31, 2012, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.

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Internal Control over Financial Reporting

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

The managements of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant’s financial statements presented in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Each Registrant’s management assessed the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2012. In making this assessment, each management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework.

Based on each management’s assessment and the criteria set forth by COSO, each Registrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2012.

The Registrants’ registered public accounting firm has issued an attestation report on each Registrant’s internal control over financial reporting.

Changes in Internal Controls over Financial Reporting

Under the supervision and with the participation of each Registrant’s management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 2012 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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Attestation Report of Registered Public Accounting Firm

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Corporation and Subsidiaries

New Orleans, Louisiana

We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2012, based on criteria established in Internal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Corporation and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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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 internal control over financial reporting of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of

Entergy Gulf States Louisiana, L.L.C.

Baton Rouge, Louisiana

We have audited the internal control over financial reporting of Entergy Gulf States Louisiana, L.L.C. (the “Company”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 27, 2013 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of

Entergy Louisiana, LLC and Subsidiaries

Baton Rouge, Louisiana

We have audited the internal control over financial reporting of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Mississippi, Inc.

Jackson, Mississippi

We have audited the internal control over financial reporting of Entergy Mississippi, Inc. (the “Company”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy New Orleans, Inc.

New Orleans, Louisiana

We have audited the internal control over financial reporting of Entergy New Orleans, Inc. (the “Company”) as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Entergy Texas, Inc. and Subsidiaries

Beaumont, Texas

We have audited the internal control over financial reporting of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

System Energy Resources, Inc.

Jackson, Mississippi

We have audited the internal control over financial reporting of System Energy Resources, Inc. (the “Company”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 27, 2013

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The greatest part of the Named Executive Officers’ compensation is in the form of "at risk" performance-based compensation, in order to focus the executives on the achievement of superior results and align compensation with shareholder value.

●

A substantial portion of the Named Executive Officers' compensation is delivered in the form of equity awards, which are required to be retained until stock ownership targets are met.

Entergy Corporation believes this philosophy has enabled us to closely align executive compensation with corporate performance and shareholder value, while at the same time attracting and retaining the highest caliber of executive talent.

The Starting Point

To develop a competitive compensation program, the Personnel Committee annually reviews compensation data from two sources:

Survey Data

The Committee uses published and private compensation survey data to develop marketplace compensation levels for the executive officers. The data, which is compiled by the Committee’s independent compensation consultant, compares the current compensation opportunities provided to each of the executive officers against the compensation opportunities provided to executives holding similar positions at companies with corporate revenues similar to Entergy Corporation’s. For non-industry specific positions such as a chief financial officer, the Committee reviews general industry data for total cash compensation (base salary and annual incentive). For management positions that are industry-specific such as Group President, Utility Operations, the Committee reviews data from utility companies for total cash compensation. However, for long-term incentives, all positions are reviewed relative to utility market data. The survey data reviewed by the Committee covers hundreds of companies across a broad range of industries and over 60 investor-owned utility companies in the utility sector. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identities of the companies participating in compensation survey data are not disclosed to, or considered by, the Committee in its decision-making process and, thus, are not considered material by the Committee.

The Committee uses the survey data to develop compensation opportunities 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. The Committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the eight (8) other executive officers of Entergy Corporation who constitute what is referred to as the Office of the Chief Executive each have a target compensation opportunity that falls within the range of 85% – 115% of the 50th percentile of the survey data. Actual compensation received by an individual officer may be above or below the 50th percentile based on an individual officer’s skills, performance, experience and responsibilities, company performance, and internal pay equity. In 2012 the target compensation for the Named Executive Officers did not exceed 115% of the 50th percentile of the survey data.

Proxy Analysis

Although the survey data described above is the primary data used in determining compensation, the Committee reviews data derived from proxy statements as an additional point of comparison. The proxy data is used to compare the compensation levels of the Named Executive Officers with the compensation levels of the corresponding top five highest paid executive officers of the companies included in the Philadelphia Utility Index, as reported in their proxy statements, based on pay rank and without regard to roles and responsibilities. The Personnel Committee uses this analysis to evaluate the overall reasonableness of Entergy Corporation’s compensation programs. The following companies were included in the Philadelphia Utility Index at the time the proxy data was compiled:

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· AES Corporation	· El Paso International
· Ameren Corporation	· Exelon Corporation
· American Electric Power Co. Inc.	· FirstEnergy Corporation
· CenterPoint Energy Inc.	· NextEra Energy
· Consolidated Edison Inc.	· Northeast Utilities
· Covanta Holding Corporation	· PGE Corporation
· Dominion Resources Inc.	· Public Service Enterprise Group, Inc.
· DTE Energy Company	· Southern Company
· Duke Energy Corporation	· Xcel Energy
· Edison International

Factors Used to Determine Compensation

When determining each compensation element for executive officers, the Personnel Committee in the case of Mr. Leonard, Mr. Denault, and Mr. West, and in the case of the other Named Executive Officers, their supervisors, consider some or all of the following factors:

·	Analysis provided by the Committee's independent compensation consultant of compensation practices at industry peer group companies and the general market for comparable positions in companies Entergy Corporation’s size;

·	Competitiveness of Entergy's executive compensation programs and Entergy Corporation’s ability to attract and retain top executive talent;

·	Individual performance of each Named Executive Officer;

·	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 Annual Incentive Plan;

·	Internal pay equity and the executive pay structure;

·	The Committee's assessment of other elements of compensation provided to the Named Executive Officer; and

·	The Chief Executive Officer’s recommendations, for all Named Executive Officers other than himself.

Mr. Leonard, Entergy Corporation’s Chief Executive Officer, received a higher compensation level compared to the other Named Executive Officers to reflect the following factors:

·	Market practices that compensate chief executive officers at greater potential compensation levels with more “pay at risk” than other named executive officers; and

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 critical factors such as: leadership, strategic planning, financial results, succession planning, communications with Entergy Corporation’s stakeholders, external relations with the communities and industries in which Entergy Corporation operates and his relationship with the Board.

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Executive Compensation Elements

Short-Term Compensation

Base Salary

Pay data is analyzed and used to determine the base salaries for all of the Named Executive Officers. Base salary is a component of the Named Executive Officers’ 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 and its use ensures a competitive compensation package for the Named Executive Officers.

The use of “internal pay equity” in setting merit increases assists us in determining whether a change in an executive officer’s role and responsibilities relative to other executive officers requires an adjustment to the officer’s salary. The Committee, however, has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.

In 2012, all of the Named Executive Officers received merit increases in their base salaries in the range of 2 to 3 percent, except for Mr. Bunting, Ms. Mount, and Ms. Rainer. The increases in base salary were made in light of current economic conditions and the projected growth in executive salaries in 2012 based on general industry surveys obtained from human resources consulting firms, as well as, an internal pay equity comparison. Upon assuming the position of Chief Accounting Officer of Entergy and the Subsidiaries, Ms. Mount’s base salary increased 27% to $280,000, Ms. Rainer’s base salary was increased 22% to $275,000 when she became President, Entergy Texas, and Mr. Bunting’s base salary was increased 52% to $560,000 when he became Group President, Utility Operations. Their salaries were increased to reflect their new roles and responsibilities and was based on the internal pay equity and market information provided by the Personnel Committee’s independent compensation consultant.

The following table sets forth the 2011 and 2012 base salaries for the Named Executive Officers. Changes in base salaries were effective in April of each of the years shown, except for Mr. Bunting, Ms. Mount, and Ms. Rainer whose salaries were effective on the date of their promotion in 2012.

Named Executive Officer	2011 Base Salary	2012 Base Salary

J. Wayne Leonard	$1,323,800	$1,350,276
Leo P. Denault	$ 655,200	$ 674,856
Roderick K. West	$ 572,000	$ 589,160
Theodore H. Bunting, Jr.	$ 359,212	$ 560,000
Joseph F. Domino	$ 324,104	$ 330,550
Haley R. Fisackerly	$ 283,250	$ 288,950
Hugh T. McDonald	$ 330,185	$ 336,800
William M. Mohl	$ 335,550	$ 342,250
Alyson M. Mount	$ 214,712	$ 280,000
Sallie T. Rainer	$ 220,629	$ 275,000
Charles L. Rice	$ 247,200	$ 252,100

Annual Incentive Plan

Performance-based incentives are included in the Named Executive Officers’ compensation packages because Entergy Corporation believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall goals and strategic direction that the Board has set for Entergy Corporation. 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.

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Under the Annual Incentive Plan, Entergy Corporation uses a performance metric known as the Entergy Achievement Multiplier to determine the percentage of target annual plan opportunities that will be paid each year to each Named Executive Officer, subject to adjustment based on individual performance.

Each year the Personnel Committee reviews the performance measures used to determine the Entergy Achievement Multiplier. In December 2011 the Personnel Committee decided to retain for 2012 the performance measures used for determining the 2011 Entergy Achievement Multiplier. These measures were consolidated 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 with shareholder value over the long-term;

·	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 70% of the industry peer group companies use earnings per share as an incentive measure.

The Committee sets minimum, target, and maximum achievement levels under the Annual Incentive Plan. There is no payout for performance at or below the minimum achievement level, the payout for performance at target is 100% of the target payout, and the payout for performance at or above the maximum achievement level is 200% of target. Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight-line interpolation. 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 five years ending with 2012, the average Entergy Achievement Multiplier was 132% of target.

In December 2011, the Committee set the 2012 target award for incentives to be paid for 2012 under the Annual Incentive Plan for Entergy Corporation’s Chief Executive Officer at 120% of his base salary and the target awards for Mr. Denault and Mr. West at 70% of their respective base salaries. The target awards for the other Named Executive Officers were set as follows: Theodore H. Bunting, Jr. (70%); Joseph F. Domino (50%); Haley Fisackerly (40%); Hugh T. McDonald (50%); William M. Mohl (60%); Alyson M. Mount, (60%); Sallie T. Rainer (40%); and Charles L. Rice, Jr. (40%).

The target awards for the Named Executive Officers (other than Entergy Corporation named executive officers) were set by their respective supervisors (subject to ultimate approval of Entergy’s Corporation Chief Executive Officer) who allocated a potential incentive pool established by the Personnel Committee among various of their direct and indirect reports.

Target awards are set based on an executive officer’s position and executive management level within the Entergy organization. Executive management levels at Entergy range from Level 1 through Level 4. At December 31, 2012, Mr. Bunting, Mr. Denault, and Mr. West held positions in Level 2, Ms. Mount and Mr. Mohl held positions in Level 3 and the remaining Named Executive Officers held 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 January 2012, the Committee determined the Annual Incentive Plan targets to be used for purposes of determining annual bonuses for 2012. The Committee’s determination of the target levels was made after full Board review of management’s 2012 financial plan for the Entergy System companies, upon recommendation of the Finance Committee, and after the Committee’s determination that the established targets aligned with Entergy Corporation’s anticipated 2012 financial performance as reflected in the financial plan and Entergy Corporation’s published earnings guidance. In keeping with past practice with respect to known special items that would be excluded from operational earnings, the Committee also determined, based on the recommendation of the Finance Committee, that for purposes of measuring performance against such targets, an adjustment would be made to exclude the effect on as-reported results of activities associated with Entergy Corporation’s planned ITC Transaction (considered a special item). The Committee therefore established the following targets for purposes of measuring management performance against as-reported results, adjusted to exclude the effect on reported results of activities associated with the ITC Transaction.

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	Minimum	Target	Maximum
Earnings Per Share ($)	$5.22	$5.80	$6.38
Operating Cash Flow ($ billion)	$2.840	$3.240	$3.640

In January 2013, the Committee and full Board reviewed Entergy Corporation’s as-reported and operational earnings per share and operating cash flow results against the established performance objectives reflected in the above table. The Committee noted that in 2012, Entergy Corporation’s as-reported results included, in addition to the special item for costs associated with the proposed ITC Transaction, a special item for an asset impairment taken in accordance with generally accepted accounting principles in connection with the Vermont Yankee nuclear plant and triggered by state actions to shut down the plant. Both of these special items were excluded from Entergy Corporation’s as-reported earnings per share and operating cash flow for purposes of measuring performance against the previously established targets. Regarding the Vermont Yankee impairment, certain benefits to operational earnings resulting from the impairment, such as reduced depreciation expense, also were excluded. In making the determination to exclude the effect of the Vermont Yankee impairment, the Committee took into account not only the fact that it was a special item not included in operational earnings, but also management’s performance in formulating and executing Entergy Corporation’s strategy with respect to Vermont Yankee.

The Committee also considered the impact on as-reported and operational earnings and operating cash flow of certain costs incurred in connection with Hurricane Isaac, which struck the Entergy System service territory in late August 2012 and left more than 787,000 customers without power, making it the fourth-most significant storm in Entergy System’s history in terms of outages. The Committee specifically noted the unusual pressure on Entergy System personnel to restore these outages quickly, due to the large number of customers who sheltered in place, and the Entergy System’s outstanding performance in that regard. In light of this performance, the Committee, based on the recommendation of the Finance Committee and the full Board of Directors, adjusted as-reported results to exclude not only the special items noted above, but also the effects of Hurricane Isaac for purposes of measuring management’s performance against the targets set in January 2012 and determining the Entergy Achievement Multiplier. This adjustment had a negligible effect on earnings per share, but increased operating cash flow significantly to reflect the cash expended in the restoration effort. This was consistent with the Committee’s view that in general, management’s performance for such purposes should be measured against operational results, subject to adjustment in appropriate circumstances for unusual or extraordinary events or performance.

The Personnel Committee determined that after taking into account the adjustments noted above, Entergy Corporation had exceeded its earnings per share goal, but had fallen short of its operating cash flow goal. Based on this review and the recommendation of the Finance Committee and the Board of Directors, in January 2013, the Personnel Committee therefore certified the 2012 Entergy Achievement Multiplier at 104% of target. This determination was subsequently ratified by the full Board of Directors.

Under the terms of the Annual Incentive Plan’s Management Effectiveness Program, the 2012 Entergy Achievement Multiplier was automatically increased by 25% for the members of the Office of the Chief Executive, subject to the Personnel Committee’s discretion to reduce or eliminate the increase altogether. In January 2013 the Committee eliminated the Management Effectiveness Program with respect to the 2012 incentive awards, reflecting the Personnel Committee’s determination that the performance levels achieved by Entergy Corporation’s management did not warrant application of this enhancement. After consultation with the Chief Executive Officer with respect to the other members of the Office of the Chief Executive and based on its evaluation of the performance of the Chief Executive Officer and other members of the Office of Chief Executive, the Committee applied an additional downward adjustment to the awards to be paid to all of the members of the Office of the Chief Executive, including Mr. Leonard, Mr. Denault, Mr. Bunting, and Mr. West which had the effect of reducing their awards from 104% of target to 95% of target. The Committee made this adjustment based on its determination that despite the many accomplishments of management in 2012 and strong operational performance, management had not fully met the Committee’s expectations with respect to Entergy Corporation’s safety performance.

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After the Entergy Achievement Multiplier was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s current Chief Executive Officer, Mr. Denault, with input from Mr. Leonard, allocated incentive award funding to the business units based on their business unit results (referred to as the “line of business multiplier”). Individual awards were determined based on the line of business multiplier as well as individual officer performance.

The following table shows the Annual Incentive Plan payments as a percentage of base salary for 2012, as well as the incentive awards paid to each Named Executive Officer for 2012:

Named Executive Officer	Target as Percentage of Base Salary	Payout as Percentage of Base Salary	2012 Annual Incentive Award
J. Wayne Leonard	120%	114%	$1,539,315
Leo P. Denault	70%	66%	$ 448,779
Roderick K. West	70%	66%	$ 391,791
Theodore H. Bunting, Jr.	70%	66%	$ 372,400
Joseph F. Domino	50%	50%	$ 165,000
Haley R. Fisackerly	40%	48%	$ 139,000
Hugh T. McDonald	50%	60%	$ 202,000
William M. Mohl	60%	88%	$ 300,000
Alyson M. Mount	60%	75%	$ 210,000
Sallie T. Rainer	40%	47%	$ 128,000
Charles L. Rice	40%	46%	$ 115,000

Long-Term Incentive Compensation

The goal for long-term incentive compensation is to focus and reward the executive officers for building shareholder value and to increase the executive officers’ ownership in Entergy Corporation’s common stock. In the long-term incentive compensation programs, Entergy Corporation uses a mix of performance units, restricted stock, and stock options. Performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock appreciation, dividend payments, and stock price relative to the companies in the Philadelphia Utility Index. Restricted stock ties the executive officers’ long-term financial interest to the long-term financial interests of Entergy Corporation’s shareholders. Stock options provide a direct incentive to increase the price of Entergy Corporation common stock. In addition, Entergy Corporation occasionally awards restricted stock units for retention purposes or to offset forfeited compensation in order to attract officers and managers from other companies. The target value of long-term incentive compensation is allocated 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value, all based on their grant date fair values.

All of the performance units, shares of restricted stock, and stock options granted to the Named Executive Officers in 2012 were awarded under the 2011 Equity Ownership Plan. All equity awards granted under the equity ownership plans require both a change in control and an involuntary job loss or substantial diminution of duties (a “double trigger”) for the acceleration of these awards upon a change in control.

Performance Unit Program

Entergy Corporation issues performance unit awards to the Named Executive Officers under the Long-Term Performance Unit Program. Historically, each performance unit equals the cash value of one share of Entergy Corporation common stock at the end of the three-year performance period. Each unit also earns the cash equivalent of the dividends paid during the performance period. Dividends accrued during the performance period are paid out only to the extent that the performance measures are achieved and a payout under the program for that period occurs. The Long-Term 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. Beginning with the 2012-2014 performance period, upon vesting, the performance units granted under the Long-Term Performance Unit Program will be settled in shares of Entergy Corporation common stock rather than cash. Accrued dividends on any shares earned during the performance period will also be converted and paid in shares of Entergy Corporation common stock. Entergy Corporation modified the form of payment to align the method of payment with market practice and to encourage the executives to own shares of Entergy Corporation common stock.

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The Long-Term Performance Unit Program specifies a minimum, target and maximum achievement level. Entergy Corporation measures performance 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 identified the Philadelphia Utility Index as the industry peer group for total shareholder return performance because the companies included in this index, in the aggregate, approximate Entergy Corporation in terms of business and scale. The Personnel Committee chose relative 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 period. It also takes into account dividends paid by the companies in this index and normalizes certain 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 Long-Term Performance Unit Program may be participating in up to three performance periods. Currently, participants are participating in the 2011-2013, the 2012-2014, and the 2013-2015 performance periods.

2012-2014 Performance Unit Program Grants. Subject to achievement of performance levels, the following target amounts for the 2012-2014 performance period were:

·	26,900 performance units for Mr. Leonard;

·	5,400 performance units for Mr. Denault and Mr. West;

·	4,983 performance units for Mr. Bunting;

·	1,500 performance units for Mr. Domino, Mr. Fisackerly, and Mr. McDonald;

·	2,400 performance units for Mr. Mohl;

·	2,067 performance units for Ms. Mount;

·	1,292 performance units for Ms. Rainer; and

·	1,500 performance units for Mr. Rice.

The range of payouts under the program is shown below.

Performance Level	Minimum	Target	Maximum
Total Shareholder Return	25th percentile	50th percentile	75th percentile
Payouts	25% of target	100% of target	200% of Target

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 Long-Term Performance Unit Program at the outset of each performance period.

Payout for the 2010-2012 Performance Period. For the 2010-2012 performance period, the target amounts established in January 2010 were:

·	22,300 performance units for Mr. Leonard;

·	5,300 performance units for Mr. Denault;

·	4,583 performance units for Mr. West;

·	2,803 performance units for Mr. Bunting;

·	1,000 performance units for Mr. Domino, Mr. Fisackerly, and Mr. McDonald;

·	2,000 performance units for Mr. Mohl; and

·	833 performance units for Mr. Rice.

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Ms. Mount and Ms. Rainer were not participants in the 2010-2012 performance period of the Long-Term Performance Unit Program. Participants could earn performance units based on relative total shareholder return and on the following range of payouts:

Performance Level	Minimum	Target	Maximum
Total Shareholder Return	25th percentile	50th percentile	75th percentile
Payouts	10% of target	100% of target	250% of Target

In January 2013, the Committee assessed Entergy Corporation's total shareholder return for the 2010-2012 performance period in order to determine the actual number of performance units to be paid to Performance Unit Program participants for the 2010-2012 performance period. The Committee compared Entergy Corporation's total shareholder return against the total shareholder return of the companies that comprise the Philadelphia Utility Index. Based on this comparison, the Committee concluded that Entergy Corporation’s performance for the 2010-2012 performance period, ranked in the bottom quartile. This resulted in a zero payout under the Performance Unit Program for the 2010-2012 performance period.

Stock Options and Restricted Stock

Entergy Corporation grants stock options and restricted stock as part of the long-term incentive awards to the executive officers. These awards are intended to:

·	Align the interests of executive officers with the interests of shareholders by tying executive officers’ long-term financial interests to the long-term financial interests of shareholders;

·	Act as a retention mechanism for key executives officers; and

·	Maintain a market competitive position for total compensation.

As previously discussed, several factors are considered in determining the amount of stock options and shares of restricted stock granted to the Named Executive Officers. For restricted stock and stock option awards, the assessment of individual performance of each Named Executive Officer is the most important factor in determining the number of shares of restricted stock and options awarded. The Committee, in consultation with Entergy Corporation’s Chief Executive Officer, reviews each officer’s performance, role and responsibilities, strengths, and developmental opportunities. It also considers Entergy Corporation’s significant achievements for the prior year.

The following table sets forth the number of stock options and shares of restricted stock granted to each Named Executive Officer in 2012. The exercise price for each option was $71.30, which was the closing price of Entergy Corporation common stock on the date of grant.

Named Executive Officer	Stock Options	Shares of Restricted Stock
J. Wayne Leonard	89,000	11,600
Leo P. Denault	30,000	4,000
Roderick K. West	30,000	4,000
Theodore H.Bunting, Jr.	9,000	2,100
Joseph F. Domino	7,300	700
Haley R. Fisackerly	4,600	1,200
Hugh T. McDonald	4,600	1,300
William M. Mohl	7,400	1,500
Alyson M. Mount	-	1,500
Sallie T. Rainer	-	1,300
Charles L. Rice	4,600	1,050

The stock option and restricted stock grants awarded to the Named Executive Officers were determined based on the factors described above. The executive officers received a larger number of stock options in 2012 as compared to 2011 in response to market data that indicated a higher level of awards was warranted. Ms. Mount and Ms. Rainer were not eligible to receive stock options when the options were granted in 2012.

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Stock Options. Under the equity plans, all stock options must have an exercise price equal to the fair market value of Entergy Corporation common stock on the date of grant. The stock options vest over a three-year period and have a ten-year term from the date of grant. The equity ownership plans prohibit the repricing of “underwater” stock options without shareholder approval.

Entergy Corporation has not adopted a formal policy regarding the granting of options at times when Entergy Corporation is in possession of material non-public information. However, options are generally granted to Named Executive Officers only during the month of January in connection with the annual executive compensation decisions. On occasion, options may be granted at other times to newly hired employees or existing employees for retention or other limited purposes.

Restricted Stock. Shares of restricted stock vest over a three-year period, have voting rights, and accrue dividends during the vesting period. Upon vesting, shares of Entergy Corporation common stock will be distributed along with the dividends that have accrued on the vested shares. The grant of restricted stock awards replaced a portion of the stock option awards historically granted to the executive officers. Entergy Corporation believes the use of restricted stock enhances retention, mitigates the burn rate, and assists in building executive ownership of Entergy Corporation common stock.

For additional information regarding stock options and shares of restricted stock awarded in 2012 to each of the Named Executive Officers, see the 2012 Grants of Plan-Based Awards table.

Restricted Stock Units

Restricted stock units granted under the 2011 Equity Ownership Plan represent phantom shares of Entergy Corporation common stock (i.e., non-stock interests that have an economic value equivalent to a share of Entergy’s Corporation common stock). Restricted stock units are occasionally granted for retention purposes, to offset forfeited compensation from a previous employer, or for other limited purposes. If all conditions of the grant are satisfied, restrictions on the restricted stock units lift at the end of the restricted period, and a cash equivalent value of the restricted units is paid to the holder of the award. The settlement price is equal to the number of restricted stock units multiplied by the closing price of Entergy Corporation common stock on the date restrictions lift. Restricted stock units are not entitled to dividends or voting rights. Restricted units are generally time-based awards for which restrictions lift, subject to continued employment, generally over a two- to five-year period.

In May 2012, the Committee granted Mr. Domino, Entergy Corporation’s Chief Integration Officer 6,000 restricted stock units in order to continue his employment with Entergy Corporation as Mr. Domino had been planning on retiring in 2012. Entergy Corporation requested that Mr. Domino remain employed in order to provide his leadership skills in light of the strategic challenges associated with the completion of the ITC Transaction. In determining the size of the grant, the Committee considered the declining value of his non-qualified retirement benefits resulting from the request to stay.

The restricted stock units will vest in full on May 31, 2014. On the vesting date, Entergy Corporation will pay Mr. Domino, subject to payment of withholding taxes, a cash amount equal to the closing price of a share of Entergy Corporation’s common stock on that date multiplied by the number of restricted stock units granted. At the discretion of Entergy Corporation’s Chief Executive Officer, Mr. Domino’s restricted stock units may vest at an earlier date if the ITC transaction closes early or Entergy Corporation publicly announces that the ITC Transaction has been terminated.

No other Named Executive Officer received a restricted stock unit grant in 2012.

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Benefits, Perquisites, Agreements, and Post-Termination Plans

Pension Plan, Pension Equalization Plan, and System Executive Retirement Plan

Retirement Plans

The Named Executive Officers participate in an Entergy Corporation-sponsored tax qualified pension plan that covers a broad group of employees. In addition, each Named Executive Officer (other than Entergy Corporation’s Chief Executive Officer) participates in the Pension Equalization Plan and System Executive Retirement Plan, two non-qualified supplemental retirement plans sponsored by Entergy Corporation. Under the terms of the Pension Equalization Plan and System Executive Retirement Plan, an employee participating in both plans is eligible to receive only the greater of the two benefits computed in accordance with the terms of and conditions of each plan.

The Committee believes that these plans are an important part of the executive compensation programs because they assist 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 Corporation. 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 us. The plans thereby encourage the most senior executives to remain employed by us and continue their work on behalf of Entergy Corporation’s shareholders. See the 2012 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 eligible earnings under the plan for that pay period. Entergy Corporation maintains the Savings Plan for its employees, including the Named Executive Officers, to encourage Entergy Corporation’s 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. Entergy Corporation believes 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 Annual Incentive Plan awards, and until 2014, 100% of their awards under the Long-Term Performance Unit Program into either or both Entergy Corporation-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 Corporation provides these benefits because the Committee believes it is standard market practice to permit officers to defer the cash portion of their compensation. Entergy Corporation believes that providing this benefit is important as a retention and recruitment tool as many, if not all, of the companies with which Entergy Corporation competes for executive talent provide a similar arrangement to their senior executive officers. See the 2012 Non-qualified Deferred Compensation table for additional information regarding the operation of the Executive Deferred Compensation Plan.

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Health and 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 and 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 of the executive officers, including the Named Executive Officers, are eligible to participate in the 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 general long-term disability plan).

Perquisites

The Named Executive Officers are provided with a limited number of 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. In 2012 the Named Executive Officers were offered: corporate aircraft usage, relocation and housing benefits, and annual physical exams. In 2011, Entergy Corporation discontinued providing personal financial counseling for its executive officers and for members of the Office of the Chief Executive, club dues and tax gross up payments on any perquisites (except for relocation benefits) were discontinued. The Named Executive Officers did not receive any additional compensation for the lost value of these discontinued perquisites. Certain of the Named Executive Officers that are not members of the Office of the Chief Executive were provided in 2012 with club dues and tax gross up payments on some perquisites. For security and business convenience reasons, Entergy Corporation permits the Chief Executive Officer to use the corporate aircraft at Entergy Corporation’s 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. From time to time, tickets are made available to cultural and sporting events available to employees, including the Named Executive Officers, for business purposes. If not utilized for business purposes, the tickets are made available to employees, including the Named Executive Officers, for personal use. For additional information regarding perquisites, see the "All Other Compensation" column in the 2012 Summary Compensation Table.

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 competes 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 Corporation’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 in connection with a change in control. 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 Annual 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 times 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 Annual Incentive Plan for the fiscal year immediately preceding the fiscal year in which the termination of employment occurs or (ii) the average Annual Incentive Plan award for the two fiscal years immediately preceding the fiscal year in which the termination of employment occurs. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. The executive officers will not receive any tax gross up payments on any severance benefits received under this plan.

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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 that officer. 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 annual incentive award must be approved by Entergy Corporation’s shareholders.

During 2012, Entergy Corporation had retention agreements with Mr. Denault and Mr. Leonard. In general, Mr. Denault’s retention agreement provides for "change in control" payments and other benefits in lieu of those provided under the System Executive Continuity Plan. As with any severance benefits paid under the System Executive Continuity Plan, Mr. Denault will not receive tax gross up payments on any severance benefits he may receive under his agreement. Mr. Denault’s retention agreement was designed to reflect the competition for chief financial officer talent in the marketplace and the Committee’s assessment of the critical role this position plays in executing Entergy Corporation’s long-term financial and other strategic objectives. Based on the market data provided by its former independent compensation consultant, the Committee believes the benefits and payment levels under Mr. Denault’s retention agreement are consistent with market practices.

Pursuant to his retention agreement, upon retirement, Mr. Leonard was eligible to receive a lump sum payment equal to 60% of his “final average compensation” (as described in the description of the System Executive Retirement Plan) reduced by other benefits to which he was entitled from Entergy Corporation-sponsored pension plan and prior employer pension plans. Mr. Leonard was not a participant in either the Pension Equalization or System Executive Retirement Plans and received the supplemental retirement payment in lieu of benefits from these plans. The terms of Mr. Leonard’s supplemental retirement benefit contained in his retention agreement were negotiated at the time his employment with Entergy Corporation commenced 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 Corporation 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.

For additional information regarding the System Executive Continuity Plan and Mr. Leonard’s and Mr. Denault’s retention agreements described above, see “2012 Potential Payments upon Termination or Change in Control.”

Compensation Program Administration

Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in its industry as well as Fortune 500 companies. Some of these practices include the following:

Clawback Provisions

Entergy Corporation has adopted the Entergy Corporation Policy Regarding Recoupment of Certain Compensation. This policy covers individuals subject to Section 16 of the Exchange Act. Under the policy, the Committee will require reimbursement of incentives paid to these executive officers where:

(i) 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 (ii) a material miscalculation of a performance award occurs whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or

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·	in the Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award whether or not the financial statements were restated.

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 Entergy Corporation’s Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Section 304 of the Sarbanes-Oxley Act of 2002.

Stock Ownership Guidelines

For many years, Entergy Corporation has had stock ownership guidelines for executives, including the Named Executive Officers. These guidelines are designed to align the executives’ long-term financial interests with those of Entergy Corporation’s shareowners. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines. The ownership guidelines are as follows:

Role	Value of Common Stock to be Owned
Chief Executive Officer	5 times base salary
Executive Vice Presidents	4 times base salary
Senior Vice Presidents	2.5 times base salary
Vice Presidents	1.5 times base salary

Further, to ensure compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines: (i) upon exercising any stock option, he or she must retain at least 75% of the after-tax net profit from such stock option exercise in the form of Entergy common stock, (ii) he or she must retain all net after-tax shares of Entergy Corporation’s restricted stock received upon vesting, and (iii) he or she must retain all net after-tax shares paid out under the Long-Term Performance Unit Program, which will payout 100% in Entergy Corporation stock commencing with the 2012-2014 performance period.

Trading Controls and Anti-Pledging and Anti-Hedging Policies

Executive officers, including the Named Executive Officers, are required to receive the permission of Entergy Corporation’s General Counsel prior to entering into any transaction involving company securities, including gifts, other than the exercise of employee stock options. Trading is generally permitted only during open trading windows occurring immediately following the release of earnings. Employees, who are subject to trading restrictions, including the Named Executive Officers, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans may be entered into only during an open trading window and must be approved by Entergy Corporation. The Named Executive Officer bears full responsibility if he or she violates corporate policy by permitting shares to be bought or sold without pre-approval or when trading is restricted.

Entergy Corporation also prohibits its directors and executive officers, including the Named Executive Officers, from pledging any Entergy Corporation securities or entering into margin accounts involving Entergy Corporation securities. These transactions are prohibited because of the potential that sales of Entergy Corporation securities could occur outside trading periods and without the required approval of the General Counsel.

Entergy Corporation also has adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving Entergy Corporation’s 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 Entergy Corporation’s stock or transactions involving “short-sales” of Entergy Corporation’s stock. The Board adopted this policy to require officers, directors, and employees to continue to own Entergy stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’s other shareholders

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Compensation Consultant Independence Policy

To ensure the independence of the Personnel Committee’s compensation consultant, the Board has 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 year. In 2012 the Personnel Committee’s independent compensation consultant, Pay Governance LLC, did not provide any services to Entergy Corporation other than its services to the Personnel Committee. 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 the executive compensation consultant’s independence is maintained.

Roles and Responsibilities

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 the Named Executive Officers. The Committee works with executive management to ensure that the compensation policies and practices are consistent with Entergy Corporation’s values and support the successful recruitment, development and retention of executive talent so Entergy Corporation can achieve its business objectives and optimize long-term financial returns. The Committee evaluates executive pay each year to ensure that the compensation policies and practices are consistent with its philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to the 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 the Chief Executive Officer.

Role of Chief Executive Officer

The Personnel Committee solicits recommendations from Entergy Corporation’s Chief Executive Officer with respect to compensation decisions for individual Named Executive Officers (other than himself).

Specifically, Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of each Named Executive Officer and recommends compensation levels to be awarded to each Named Executive Officer other than himself. In addition, the Committee may request that the Chief Executive Officer provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in the structure of bonus programs. The Personnel Committee also relies on the recommendations of the senior human resources executives with respect to compensation decisions, policies, and practices. Entergy Corporation’s Chief Executive Officer 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.

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The Chief Executive Officer 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 the portion of 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 2012, Mr. Leonard attended 3 meetings of the Personnel Committee.

Role of the Compensation Consultant

The Personnel Committee has the sole authority from the Board of Directors for the appointment, compensation, and oversight of its outside compensation consultant. In 2012 the Personnel Committee retained Pay Governance LLC 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.

During 2012, Pay Governance assisted the Committee with its responsibilities related Entergy Corporation’s compensation programs for its executives. Specifically, the Committee directed Pay Governance to: (i) regularly attend meetings of the Committee; (ii) conduct studies of competitive compensation practices; (iii) identify Entergy Corporation’s market surveys 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 Corporation for consideration by the Committee. A senior consultant from Pay Governance attended all Personnel Committee meetings to which he was invited in 2012. Pay Governance did not provide any other services to Entergy Corporation in 2012.

Tax and Accounting Considerations

Section 162(m) of the Code limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to the 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 its Named Executive Officers. Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to the 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's success, such as encouraging employee retention and rewarding achievement of key corporate goals.

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

2012 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, 2012, 2011, and 2010. 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 (1)	Year	Salary (2)	Bonus (3)	Stock Awards (4)	Option Awards (5)	Non-Equity Incentive Plan Compensation (6)	Change in Pension Value and Non-qualified Deferred Compensation Earnings (7)	All Other Compensation (8)	Total

Theodore H. Bunting, Jr.	2012	$473,286	$ -	$585,787	$84,780	$372,400	$623,800	$23,817	$2,163,870
Former principal financial	2011	$356,884	$ -	$351,108	$78,064	$400,000	$632,100	$14,094	$1,832,250
officer – Entergy Arkansas,	2010	$350,448	$ -	$237,864	$194,155	$525,000	$392,300	$22,609	$1,722,376
Entergy Gulf States Louisiana,
Entergy Louisiana, Entergy
Mississippi, Entergy New
Orleans, Entergy Texas

Leo P. Denault	2012	$669,564	$ -	$647,594	$282,600	$448,779	$972,400	$22,657	$3,043,594
Executive Vice President and	2011	$648,512	$ -	$891,941	$287,000	$587,059	$980,400	$16,756	$3,411,668
CFO – Entergy Corp.	2010	$630,000	$ -	$573,036	$669,500	$758,520	$528,600	$52,276	$3,211,932

Joseph F. Domino	2012	$328,814	$ -	$537,755	$68,766	$165,000	$305,700	$19,443	$1,425,478
Former CEO - Entergy Texas	2011	$322,418	$ -	$172,899	$33,292	$215,000	$573,500	$19,207	$1,336,316
	2010	$317,754	$ -	$108,120	$61,594	$317,754	$224,500	$33,476	$1,063,198

Haley R. Fisackerly	2012	$287,296	$30,000	$186,225	$43,332	$139,000	$284,900	$26,781	$997,534
CEO – Entergy Mississippi	2011	$280,885	$ -	$172,899	$33,292	$150,000	$295,700	$16,603	$949,379
	2010	$274,999	$ -	$108,120	$120,510	$192,500	$190,000	$39,370	$925,499

J. Wayne Leonard	2012	$1,343,148	$ -	$2,632,339	$838,380	$1,539,315	$5,892,800	$95,884	$12,341,866
Chairman of the Board and	2011	$1,315,229	$ -	$3,163,825	$803,600	$2,033,356	$2,749,700	$65,061	$10,130,771
CEO - Entergy Corp.	2010	$1,291,500	$ -	$2,411,076	$1,807,650	$2,665,656	$ -	$104,185	$8,280,067

Hugh T. McDonald	2012	$334,891	$30,000	$193,355	$43,332	$202,000	$452,900	$38,819	$1,295,297
CEO-Entergy Arkansas	2011	$327,892	$ -	$172,899	$33,292	$210,000	$485,000	$28,320	$1,257,403
	2010	$322,132	$ -	$108,120	$61,594	$297,972	$205,000	$54,990	$1,049,808

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(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name and Principal Position (1)	Year	Salary (2)	Bonus (3)	Stock Awards (4)	Option Awards (5)	Non-Equity Incentive Plan Compensation (6)	Change in Pension Value and Non-qualified Deferred Compensation Earnings (7)	All Other Compensation (8)	Total

William M. Mohl	2012	$340,447	$30,000	$268,014	$69,708	$300,000	$448,600	$17,169	$1,473,938
CEO-Entergy Louisiana and	2011	$332,751	$ -	$303,794	$70,028	$265,000	$388,900	$26,668	$1,387,141
CEO-Entergy Gulf States	2010	$299,193	$ -	$216,240	$120,510	$380,250	$166,718	$148,767	$1,331,678
Louisiana

Alyson M. Mount	2012	$252,389	$ -	$320,401	$ -	$210,000	$384,700	$11,556	$1,179,046
Acting principal financial
officer – Entergy Arkansas,
Entergy Gulf States Louisiana,
Entergy Louisiana, Entergy
Mississippi, Entergy New
Orleans, Entergy Texas

Sallie T. Rainer	2012	$251,907	$30,000	$215,262	$ -	$128,000	$581,300	$13,714	$1,220,183
CEO - Entergy Texas

Charles L. Rice, Jr.	2012	$250,781	$30,000	$175,530	$43,332	$115,000	$96,900	$24,422	$735,965
CEO-Entergy New Orleans	2011	$245,312	$ -	$154,702	$33,292	$130,000	$78,400	$20,594	$662,300
	2010	$203,879	$9,962	$90,064	$ -	$192,000	$30,944	$18,708	$545,557

Roderick K. West	2012	$584,540	$ -	$647,594	$282,600	$391,791	$991,000	$46,097	$2,943,622
Executive Vice President and	2011	$566,162	$ -	$746,361	$195,160	$512,512	$664,800	$20,261	$2,705,256
Chief Administrative Officer,	2010	$441,539	$ -	$495,514	$93,730	$662,200	$207,000	$46,915	$1,946,898
Entergy Corp.

(1)	Effective February 1, 2013, Mr. Leonard retired from Entergy. Mr. Denault succeeded Mr. Leonard as Chairman of the Board and Chief Executive Officer of Entergy Corporation. Information presented in the tables reflects the positions and compensation for each of these individuals as of December 31, 2012.
(2)	The amounts in column (c) represent the actual base salary paid to the Named Executive Officer. The 2012 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2012.
(3)	The amounts in column (d) for Mr. Fisackerly, Mr. McDonald, Mr. Mohl, Ms. Rainer, and Mr. Rice represent a cash bonus paid in recognition of their work supporting the move to MISO.
(4)	The amounts in column (e) represent the aggregate grant date fair value of restricted stock, restricted stock units, and performance units granted under the 2011 Equity Ownership Plan calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock and the restricted stock units is based on the closing price of Entergy Corporation common stock on the date of grant. 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 the 2012 performance units are as follows: Mr. Bunting, $942,109; Mr. Denault, $770,040; Mr. Domino, $213,900; Mr. Fisackerly, $213,900; Mr. Leonard, $3,835,940; Mr. McDonald, $213,900; Mr. Mohl, $342,240; Ms. Mount, $436,997; Ms. Rainer, $248,441; Mr. Rice, $213,900; and Mr. West, $770,040.

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(5)	The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2011 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.
(6)	The amounts in column (g) represent cash payments made under the Annual Incentive Plan.
(7)	The amounts in column (h), except for Mr. Leonard, include the annual actuarial increase in the present value of the Named Executive Officers’ 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 “2012 Pension Benefits”). For Mr. Leonard, who retired in February 2013, the amount was calculated using the rate with which the lump sum will actually be calculated as prescribed by the Internal Revenue Service resulting in a larger increase in pension value. None of the increase is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2012 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.
(8)	The amounts in column (i) for 2012 include (a) matching contributions by Entergy Corporation to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on perquisites; and (e) perquisites and other compensation. The amounts are listed in the following table:

Named Executive Officer	Company Contribution – Savings Plan	Dividends Paid on Restricted Stock	Life Insurance Premium	Tax Gross Up Payments	Perquisites and Other Compensation	Total
Theodore H. Bunting, Jr.	$10,500	$2,037	$3,945	$ -	$7,335	$23,817
Leo P. Denault	$10,500	$5,821	$4,041	$ -	$2,295	$22,657
Joseph F. Domino	$10,500	$1,048	$6,122	$ -	$1,773	$19,443
Haley R. Fisackerly	$10,500	$1,048	$428	$3,767	$11,038	$26,781
J. Wayne Leonard	$10,500	$13,390	$11,636	$ -	$60,358	$95,884
Hugh T. McDonald	$10,500	$1,048	$3,564	$7,930	$15,777	$38,819
William M. Mohl	$10,500	$1,279	$2,683	$ -	$2,707	$17,169
Alyson M. Mount	$10,500	$814	$242	$ -	$ -	$11,556
Sallie T. Rainer	$10,500	$580	$2,634	$ -	$ -	$13,714
Charles L. Rice, Jr.	$10,500	$755	$3,184	$2,196	$7,787	$24,422
Roderick K. West	$10,500	$3,494	$1,673	$ -	$30,430	$46,097

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. In 2012, the Named Executive Officers were offered the following personal benefits: corporate aircraft usage, relocation and housing benefits, annual physical exams, club dues for officers who are not a member of the Office of Chief Executive, and event tickets. Tickets to cultural and sporting events are purchased for business purposes; if not utilized for business purposes, the tickets are made available to the employees, including the Named Executive Officers, for personal use. The following perquisites and other compensation were provided by Entergy Corporation in 2012:

Named Executive Officer	Personal Use of Corporate Aircraft	Club Dues	Executive Physicals	Event Tickets
Theodore H. Bunting, Jr.	x		x	x
Leo P. Denault			x	x
Joseph F. Domino			x
Haley R. Fisackerly		x	x
J. Wayne Leonard	x		x	x
Hugh T. McDonald		x
William M. Mohl			x	x
Charles L. Rice, Jr.		x	x	x
Roderick K. West	x		x	x

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For security and business reasons, Entergy Corporation permits its Chief Executive Officer 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 $54,198 for fiscal year 2012. The aggregate incremental aircraft usage cost associated with Mr. West’s personal use of the aircraft was $26,574. 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.

None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.

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2012 Grants of Plan-Based Awards

The following table summarizes award grants during 2012 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 ($)	(f) Threshold (#)	(g) Target (#)	(h) Maximum (#)	(i) All Other Stock Awards: Number of Shares of Stock or Units (#) (3)	(j) All Other Option Awards: Number of Securities Under- lying Options (#) (4)	(k) Exercise or Base Price of Option Awards ($/Sh)	(l) Grant Date Fair Value of Stock and Option Awards (5)

Theodore H. Bunting, Jr. (7)	1/26/12	-	$392,000	$784,000
	1/26/12				1,246	4,983	9,967				$334,409
	5/31/12				449	1,794	3,588				$101,648
	1/26/12							2,100			$149,730
	1/26/12								9,000	$71.30	$84,780

Leo P. Denault	1/26/12	-	$472,399	$944,798
	1/26/12				1,350	5,400	10,800				$362,394
	1/26/12							4,000			$285,200
	1/26/12								30,000	$71.30	$282,600

Joseph F. Domino	1/26/12	-	$165,275	$330,550
	1/26/12				375	1,500	3,000				$100,665
	1/26/12							700			$49,910
	5/31/12							6,000(6)			$387,180
	1/26/12								7,300	$71.30	$68,766

Haley R. Fisackerly	1/26/12	-	$115,580	$231,160
	1/26/12				375	1,500	3,000				$100,665
	1/26/12							1,200			$85,560
	1/26/12								4,600	$71.30	$43,332

J. Wayne Leonard	1/26/12	-	$1,620,331	$3,240,662
	1/26/12				6,725	26,900	53,800				$1,805,259
	1/26/12							11,600			$827,080
	1/26/12								89,000	$71.30	$838,380

Hugh T. McDonald	1/26/12	-	$168,400	$336,800
	1/26/12				375	1,500	3,000				$100,665
	1/26/12							1,300			$92,690
	1/26/12								4,600	$71.30	$43,332

William M. Mohl	1/26/12	-	$205,350	$410,700
	1/26/12				600	2,400	4,800				$161,064
	1/26/12							1,500			$106,950
	1/26/12								7,400	$71.30	$69,708

Alyson M. Mount	1/26/12	-	$168,000	$336,000
(7)	5/31/12				517	2,067	4,133				$138,716
	5/31/12				330	1,319	2,639				$74,735
	1/26/12							1,500			$106,950

Sallie T. Rainer (7)	1/26/12	-	$110,000	$220,000
	5/31/12				323	1,292	2,583				$86,706
	5/31/12				158	633	1,267				$35,866
	1/26/12							1,300			$92,690

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		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 ($)	(f) Threshold (#)	(g) Target (#)	(h) Maximum (#)	(i) All Other Stock Awards: Number of Shares of Stock or Units (#) (3)	(j) All Other Option Awards: Number of Securities Under- lying Options (#) (4)	(k) Exercise or Base Price of Option Awards ($/Sh)	(l) Grant Date Fair Value of Stock and Option Awards (5)

Charles L. Rice, Jr.	1/26/12	-	$100,840	$201,680
	1/26/12				375	1,500	3,000				$100,665
	1/26/12							1,050			$74,865
	1/26/12								4,600	$71.30	$43,332

Roderick K. West	1/26/12	-	$412,412	$824,824
	1/26/12				1,350	5,400	10,800				$362,394
	1/26/12							4,000			$285,200
	1/26/12								30,000	$71.30	$282,600

(1)	The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual 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 Long-Term 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 one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2014.) Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock.
(3)	The amounts in column (i) represent shares of restricted stock granted under the 2011 Equity Ownership Plan. Shares of restricted stock vest over a three-year period, have voting rights and accrue dividends during the vesting period.
(4)	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 and have a ten-year term from the date of grant. The options were granted under the 2011 Equity Ownership Plan.
(5)	The amounts 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 4 and 5 to the Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.
(6)	In May 2012, Mr. Domino was awarded 6,000 restricted stock units under the 2011 Equity Ownership Plan. The restricted stock units will vest on May 31, 2014.
(7)	With their promotions on May 31, 2012, Mr. Bunting, Ms. Mount, and Ms. Rainer received pro-rated performance unit awards under the 2011 – 2013 Long-Term Performance Unit Program. 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, 2013.)

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2012 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 2012.

	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.	-	9,000(1)		$71.30	1/26/2022
Bunting, Jr.	2,266	4,534(2)		$72.79	1/27/2021
	9,666	4,834(3)		$77.10	1/28/2020
	12,000	-		$77.53	1/29/2019
	18,000	-		$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
								1,246(4)	$79,433
								1,074(5)	$68,468
						2,100(6)	$133,875
						1,167(7)	$74,396

Leo P. Denault	-	30,000(1)		$71.30	1/26/2022
	8,333	16,667(2)		$72.79	1/27/2021
	33,333	16,667(3)		$77.10	1/28/2020
	45,000	-		$77.53	1/29/2019
	50,000	-		$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
	34,995	-		$58.60	3/02/2014
								1,350(4)	$86,063
								1,475(5)	$94,031
						4,000(6)	$255,000
						3,334(7)	$212,543
						8,000(8)	$510,000

Joseph F. Domino	-	7,300(1)		$71.30	1/26/2022
	966	1,934(2)		$72.79	1/27/2021
	3,066	1,534(3)		$77.10	1/28/2020
	4,500	-		$77.53	1/29/2019
	7,000	-		$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
								375(4)	$23,906
								300(5)	$19,125
						700(6)	$44,625
						600(7)	$38,250
						6,000(9)	$382,500

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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 ($)
Haley R. Fisackerly	-	4,600(1)		$71.30	1/26/2022
	966	1,934(2)		$72.79	1/27/2021
	6,000	3,000(3)		$77.10	1/28/2020
	3,800	-		$77.53	1/29/2019
	5,000	-		$108.20	1/24/2018
	2,500	-		$91.82	1/25/2017
	1,000	-		$68.89	1/26/2016
								375(4)	$23,906
								300(5)	$19,125
						1,200(6)	$76,500
						600(7)	$38,250

J. Wayne Leonard	-	89,000(1)		$71.30	1/26/2022
	23,333	46,667(2)		$72.79	1/27/2021
	90,000	45,000(3)		$77.10	1/28/2020
	125,000	-		$77.53	1/29/2019
	175,000	-		$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
								6,725(4)	$428,719
								6,500(5)	$414,375
						11,600(6)	$739,500
						7,667(7)	$488,771

Hugh T. McDonald	-	4,600(1)		$71.30	1/26/2022
	966	1,934(2)		$72.79	1/27/2021
	3,066	1,534(3)		$77.10	1/28/2020
	4,500	-		$77.53	1/29/2019
	7,000	-		$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
								375(4)	$23,906
								300(5)	$19,125
						1,300(6)	$82,875
						600(7)	$38,250

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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	-	7,400(1)		$71.30	1/26/2022
	2,033	4,067(2)		$72.79	1/27/2021
	6,000	3,000(3)		$77.10	1/28/2020
	7,500	-		$77.53	1/29/2019
	9,300	-		$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
								600(4)	$38,250
								625(5)	$39,844
						1,500(6)	$95,625
						734(7)	$46,793

Alyson M. Mount	4,333	2,167(3)		$77.10	1/28/2020
	4,500	-		$77.53	1/29/2019
	4,500	-		$108.20	1/24/2018
	5,400	-		$91.82	1/25/2017
	5,000	-		$68.89	1/26/2016
	4,000	-		$69.47	1/27/2015
	1,500	-		$58.60	3/02/2014
								517(4)	$32,959
								330(5)	$21,038
						1,500(6)	$95,625
						467(7)	$29,771

Sallie T. Rainer	1,666	834(3)		$77.10	1/28/2020
	1,200	-		$77.53	1/29/2019
	2,300	-		$108.20	1/24/2018
	2,000	-		$91.82	1/25/2017
	2,500	-		$68.89	1/26/2016
	2,500	-		$69.47	1/27/2015
	1,900	-		$58.60	3/02/2014
								323(4)	$20,591
								158(5)	$10,073
						1,300(6)	$82,875
						334(7)	$21,293

Charles L. Rice, Jr.	-	4,600(1)		$71.30	1/26/2022
	966	1,934(2)		$72.79	1/27/2021
								375(4)	$23,906
								300(5)	$19,125
						1,050(6)	$66,938
						434(7)	$27,668








Roderick K. West	-	30,000(1)		$71.30	1/26/2022
	5,666	11,334(2)		$72.79	1/27/2021
	4,666	2,334(3)		$77.10	1/28/2020
	5,000	-		$77.53	1/29/2019
	8,000	-		$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
								1,350(4)	$86,063
								1,475(5)	$94,031
						4,000(6)	$255,000
						2,000(7)	$127,500
						15,000(10)	$956,250

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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 ($)

Roderick K. West	-	30,000(1)		$71.30	1/26/2022
	5,666	11,334(2)		$72.79	1/27/2021
	4,666	2,334(3)		$77.10	1/28/2020
	5,000	-		$77.53	1/29/2019
	8,000	-		$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
								1,350(4)	$86,063
								1,475(5)	$94,031
						4,000(6)	$255,000
						2,000(7)	$127,500
						15,000(10)	$956,250

(1)	Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/26/2013, 1/26/2014, and 1/26/2015.
(2)	Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/27/2013 and 1/27/2014.
(3)	The remaining unexercisable options vested on 1/28/2013.
(4)	Consists of performance units that will vest on December 31, 2014 based on Entergy Corporation’s total shareholder return performance over the 2012 – 2014 performance period 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, 2013 based on Entergy Corporation’s total shareholder return performance over the 2011 – 2013 performance period.
(6)	Consists of shares of restricted stock that vested or will vest as follows: 1/3 of the shares of restricted stock granted vest on each of 1/26/2013, 1/26/2014, and 1/26/2015.
(7)	Consists of shares of restricted stock that vested or will vest as follows: 1/2 of the shares of restricted stock granted vest on each of 1/27/2013 and 1/27/2014.
(8)	Consists of restricted stock units granted under the 2007 Equity Ownership and Long-Term Cash Incentive Plan of Entergy Corporation and Subsidiaries or “2007 Equity Ownership Plan.” The units vested on January 25, 2013.
(9)	Consists of restricted stock units granted under the 2011 Equity Ownership Plan which will vest on May 31, 2014.
(10)	Consists of restricted stock units granted under the 2007 Equity Ownership Plan which will vest on April 30, 2013.

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2012 Option Exercises and Stock Vested

The following table provides information concerning each exercise of stock options and each vesting of stock during 2012 for the Named Executive Officers.

	Options Awards		Stock Awards
(a) Name	(b) Number of Shares Acquired on Exercise (#)	(c) Value Realized on Exercise ($)	(d) Number of Shares Acquired on Vesting (#)	(e) Value Realized on Vesting ($)

Theodore H. Bunting, Jr.	-	$ -	611	$43,208

Leo P. Denault	17,633	$469,305	9,748(1)	$690,593

Joseph F. Domino	10,500	$291,857	314	$22,234

Haley R. Fisackerly	-	$ -	314	$22,234

J. Wayne Leonard	195,000	$5,564,637	54,022(2)	$3,453,577

Hugh T. McDonald	10,000	$87,966	314	$22,234

William M. Mohl	-	$ -	384	$27,126

Alyson M. Mount	1,800	$44,447	244	$17,269

Sallie T. Rainer	1,000	$12,838	174	$12,303

Charles L. Rice, Jr.	-	$ -	226	$16,009

Roderick K. West	-	$ -	1,049	$74,114

(1)	Includes the January 25, 2012 cash settlement of 8,000 restricted stock units granted under the 2007 Equity Ownership Plan.
(2)	Includes the December 3, 2012 cash settlement of 50,000 restricted stock units granted under the 2007 Equity Ownership Plan.

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2012 Pension Benefits

The following table shows the present value as of December 31, 2012, 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 2011
Theodore H. Bunting, Jr.	Non-qualified System Executive Retirement Plan	24.86	$2,708,600	$ -
	Qualified defined benefit plan	24.86	$739,400	$ -

Leo P. Denault (1)	Non-qualified System Executive Retirement Plan	28.83	$5,479,100	$ -
	Qualified defined benefit plan	13.83	$397,500	$ -

Joseph F. Domino (2)	Non-qualified System Executive Retirement Plan	42.56	$1,980,800	$ -
	Qualified defined benefit plan	39.13	$1,735,500	$ -

Haley R. Fisackerly	Non-qualified System Executive Retirement Plan	17.08	$803,700	$ -
	Qualified defined benefit plan	17.08	$400,600	$ -

J. Wayne Leonard (3)	Non-qualified supplemental retirement plan benefit	14.68	$32,027,000	$ -
	Qualified defined benefit plan	14.68	$686,100	$ -

Hugh T. McDonald (2)	Non-qualified System Executive Retirement Plan	30.93	$1,581,500	$ -
	Qualified defined benefit plan	29.44	$891,500	$ -

William M. Mohl	Non-qualified System Executive Retirement Plan	10.44	$1,119,300	$ -
	Qualified defined benefit plan	10.44	$301,900	$ -

Alyson M. Mount	Non-qualified System Executive Retirement Plan	10.35	$354,100	$ -
	Qualified defined benefit plan	10.35	$198,000	$ -

Sallie T. Rainer (2)	Non-qualified System Executive Retirement Plan	28.38	$496,100	$ -
	Qualified defined benefit plan	26.52	$742,000	$ -

Charles L. Rice, Jr.	Non-qualified System Executive Retirement Plan	3.47	$129,500	$ -
	Qualified defined benefit plan	3.47	$80,500	$ -

Roderick K. West	Non-qualified System Executive Retirement Plan	13.75	$2,007,400	$ -
	Qualified defined benefit plan	13.75	$280,600	$ -

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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 $1,727,800.
(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.

Qualified Retirement Benefits

The qualified retirement plan is a funded, tax-qualified, noncontributory 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. Benefits under the tax-qualified pension plan are calculated as an annuity payable at age 65 and equal to 1.5% of a participant's Eligible Earnings multiplied by years of service. “Eligible Earnings” generally includes the employee’s salary and eligible incentive awards, other than incentive awards paid under the Annual 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 attainment of at least age 55 and 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. Years of service under the pension plan formula cannot exceed 40. Participants are 100% vested in their benefit upon completing 5 years of vesting service. Contributions to the pension plan are made entirely by Entergy Corporation and are paid into a trust fund from which the benefits of participants will be paid.

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 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 and Mr. Leonard 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, as described below, 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.

All of the Named Executive Officers (other than Mr. Leonard) participate in both the Pension Equalization Plan and the System Executive Retirement Plan.

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The Pension Equalization Plan

The Pension Equalization Plan is a non-qualified unfunded supplemental retirement plan that provides for the payment to participants from Entergy'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 Annual Incentive Plan and if granted to an individual participant provides supplemental credited service. Participants receive their Pension Equalization Plan benefit in the form of a single sum cash distribution. The benefits under this plan are offset by benefits payable from the qualified retirement plan and may be offset by prior employer benefits. 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 (which approval is deemed given following a change in control), 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.

The System Executive Retirement Plan

The System Executive Retirement Plan provides for a single sum payment at age 65. Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to participants from Entergy’s general assets of 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 Annual 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 ratio 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 Levels 2 and 3 – includes the remaining 4 Named Executive Officers	Executives at Management Level 4
20 Years	55.0%	50.0%	45.0%
30 years	65.0%	60.0%	55.0%

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 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 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 above), 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. At December 31, 2012, Mr. Leonard had already attained the age of 55, and was 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. Mr. Leonard became eligible to receive this retirement benefit upon his retirement.

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2012 Non-qualified Deferred Compensation

The Executive Deferred Compensation Plan, the 2007 Equity Ownership Plan and the 2011 Equity Ownership Plan allow for the deferral of compensation for the Named Executive Officers. Entergy Corporation does not “match” amounts that are deferred by employees pursuant to the Executive Deferred Compensation Plan or the equity plans. With the exception of allowing for the deferral of federal and state taxes, Entergy Corporation provides no additional benefit to the Named Executive Officer for deferring any of the compensation received under these plans. Any increase in value of the deferred amounts results solely from the increase in value of the deemed investment options selected by the Named Executive Officer (phantom stock of Entergy Corporation or mutual funds available under the Savings Plan). As of December 31, 2012 none of the Named Executive Officers had deferred compensation balances under the equity ownership plans or the Executive Deferred Compensation Plan.

As of December 31, 2012, 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 T. Rowe Price investment funds that are also available to participants under the 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.

Defined Contribution Restoration Plan

Name (a)	Executive Contributions in 2012 (b)	Registrant Contributions in 2012 (c)	Aggregate Earnings in 2012 (1) (d)	Aggregate Withdrawals/ Distributions (e)	Aggregate Balance at December 31, 2012 (f)

J. Wayne Leonard	$ -	$ -	($18,761)	$ -	$208,570

(1)	Amounts in this column are not included in the Summary Compensation Table.

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2012 Potential Payments upon Termination or Change in Control

Entergy Corporation has plans and other arrangements that provide compensation to a Named Executive Officer if his or her employment is terminated under specified conditions, including following a change in control of Entergy Corporation. In addition, Mr. Leonard and Mr. Denault have individual retention agreements.

The tables below reflect the amount of compensation each of the Named Executive Officers would have received if his or her employment with an Entergy System company had been terminated under various scenarios as of December 31, 2012. For purposes of these tables, the assumed stock price was $63.75, the closing market price on that date.

Theodore H. Bunting, Jr

Group President, Utility Operations

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Group President, Utility Operations would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2012:

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)	---	---	---	---	---	---	---	$2,679,040
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$182,516	$182,516	---	$227,269
2012-2014 Performance Unit Program	---	---	---	---	$105,889	$105,889	---	$227,269
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$81,855	$81,855	---	$222,843
Medical and Dental Benefits(6)	---	---	---	---	---	---	---	$25,614
280G Tax Gross-up(9)	---	---	---	---	---	---	---	---

(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 "2012 Pension Benefits." If Mr. Bunting's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

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(2)	In the event of a qualifying 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 the product of 2.99 times the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual 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 $560,000 was assumed.
(3)	In the event of a qualifying termination related to a change in control, Mr. Bunting would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, 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. Bunting’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (2719 units) and the 2009-2011 Performance Unit Program (4,411 units). This average number of units (3,565 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $227,269 for the forfeited performance units. In the event of Mr. Bunting’s death or disability not related to a change in control, Mr. Bunting would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. For purposes of the table, the value of Mr. Bunting's awards were calculated as follows: 2011 - 2013 Plan – 2,863 (4,294 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 1,661 (4,983 * 12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of his death, disability or a change in control, all of Mr. Bunting's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Bunting’s unvested stock options granted on or after December 30, 2010 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, 2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for all of Mr. Bunting’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.
(5)	In the event of his death or disability, Mr. Bunting would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Bunting would immediately vest in all unvested restricted stock.
(6)	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.

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(7)	As of December 31, 2012, compensation and benefits available to Mr. Bunting under this scenario are substantially the same as available with a voluntary resignation.
(8)	With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, 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 on or after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payment upon a change in control.
(9)	In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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, 2012:

Benefits and Payments Upon Termination(1)	Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement(9)	Disability	Death	Change in Control(10)	Termination Related to a Change in Control
Severance Payment(2)	---	---	$3,430,293	---	---	---	---	$3,430,293
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	$277,313	---	$277,313	$277,313	---	$277,313
2012-2014 Performance Unit Program	---	---	$277,313	---	$277,313	$277,313	---	$277,313
Unvested Stock Options(4)	---	---	$0	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	$502,622	---	$502,622	$502,622	--	$502,622
Unvested Restricted Units(6)	---		$510,000	---	$510,000	$510,000	--	$510,000
COBRA Benefits(7)	---	---	$25,614	---	---	---	---	---
Medical and Dental Benefits(8)	---	---	---	---	---	---	---	$25,614
280G Tax Gross-up(11)	---	---	---	---	---	---	---	---

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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 “2012 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, 2012, 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 the product of 2.99 times the sum of (a) his annual base salary as in effect at any time within one year prior to the effective date of the Agreement (i.e., 2007) or, if higher, immediately prior to a circumstance constituting good reason plus (b) the greater of (i) his actual annual incentive award under the Annual Incentive Plan for the calendar year immediately preceding the calendar year in which Mr. Denault’s termination date occurs or (ii) Mr. Denault’s Annual Incentive Plan target award for the calendar year in which the effective date of the Agreement occurred (i.e., 2007). For purposes of this table, the award was calculated using a base salary of $674,856 and target award of 70%.
(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 2008-2010 Performance Unit Program (3,900 units) and the 2009-2011 Performance Unit Program (4,800 units). This average number of units (4,350 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $277,313 for the forfeited performance units.
(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 Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Mr. Denault’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.

(5)

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 restricted stock would immediately vest.

(6)

Mr. Denault’s 8,000 restricted units vest on January 25, 2013, provided he remains a full-time Entergy 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).

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(7)	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.
(8)	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.
(9)	As of December 31, 2012, Mr. Denault is not eligible for retirement.
(10)	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.
(11)	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;

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·	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

Chief Integration Officer

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Chief Integration Officer would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2012:

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
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)	---	---	---	---	---	---	---	$495,825
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	$51,000	$51,000	$51,000	---	$51,000
2012-2014 Performance Unit Program	---	---	---	$31,875	$31,875	$31,875	---	$51,000
Unvested Stock Options(4)	---	---	---	$0	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$34,170	$34,170		$89,123
Unvested Restricted Units(6)	---	---	$382,500	---	---	---	---	$382,500
Medical and Dental Benefits(7)	---	---	---	---	---	---	---	---
280G Tax Gross-up(10)	---	---	---	---	---	---	---	---

(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 "2012 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.

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(2)	In the event of a qualifying 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 the product of one time the sum of (a) his annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual 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 $330,550 was assumed.
(3)	In the event of a qualifying termination related to a change in control, Mr. Domino would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, 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. Domino’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $ $51,000 for the forfeited performance units. In the event of Mr. Domino’s death or disability not related to a change in control, Mr. Domino would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. For purposes of the table, the value of Mr. Domino’s awards were calculated as follows: 2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of his retirement, death, disability or a change in control, all of Mr. Domino’s unvested stock options granted prior to December 31, 2010 would immediately vest. In the event of his retirement, death, disability or qualifying termination related to a change in control, all of Mr. Domino’s unvested stock options granted on or after December 30, 2010 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. Domino exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Domino’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.
(5)	In the event of his death or disability, Mr. Domino would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Domino would immediately vest in all unvested restricted stock.
(6)	Mr. Domino's 6,000 restricted unit vest 100% on May 31, 2014 provided he remains a full-time Entergy System company employee through such vesting date. Pursuant to his restricted unit agreement, his unvested restricted units will vest immediately in the event of termination for good reason or not for cause or a termination related to change in control.

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(7)	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.
(8)	As of December 31, 2012, Mr. Domino is retirement eligible and would retire rather than voluntarily resign. Given that scenario, the compensation and benefits available to Mr. Domino under retirement are substantially the same as available with a voluntary resignation.
(9)	With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, 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 on or after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments.
(10)	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, 2012:

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
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)	---	---	---	---	---	---	---	$404,530
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$51,000	$51,000	---	$51,000
2012-2014 Performance Unit Program	---	---	---	---	$31,875	$31,875	---	$51,000
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$44,561	$44,561	---	$122,636
Medical and Dental Benefits(6)	---	---	---	---	---	---	---	$17,076
280G Tax Gross-up(9)	---	---	---	---	---	---	---	---

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(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 "2012 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 qualifying 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 the product of one time the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual 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 $288,950 was assumed.
(3)	In the event of a qualifying termination related to a change in control, Mr. Fisackerly would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, 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. Fisackerly’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $51,000 for the forfeited performance units. In the event of Mr. Fisackerly’s death or disability not related to a change in control, Mr. Fisackerly would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. For purposes of the table, the value of Mr. Fisackerly’s awards were calculated as follows: 2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of his death, disability or a change in control, all of Mr. Fisackerly’s unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Fisackerly’s unvested stock options granted on or after December 30, 2010 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, 2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Fisackerly’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.

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(5)	In the event of his death or disability, Mr. Fisackerly would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month Grant Date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Fisackerly would immediately vest in all unvested restricted stock.
(6)	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.
(7)	As of December 31, 2012, compensation and benefits available to Mr. Fisackerly under this scenario are substantially the same as available with a voluntary resignation.
(8)	With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, 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 on or after December 30, 2010 require a qualifying 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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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 then 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, 2012:

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)	---	---	---	---	---	---	---	$3,240,662
Severance Payment(3)	---	---	---	---	---	---	---	$8,882,116
Performance Units:(4)
2011-2013 Performance Unit Program	---	---	---	$1,104,979	$1,104,979	$1,104,979	---	$1,243,125
2012-2014 Performance Unit Program	---	---	---	$571,646	$571,646	$571,646	---	$1,243,125
Unvested Stock Options(5)	---	---	---	$0	$0	$0	---	$0
Unvested Restricted Stock(6)	---	---	---	---	$491,895	$491,895	---	$1,316,807
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. For additional information regarding these vested benefits and awards, see “2012 Pension Benefits.”
(2)	In the event of a qualifying 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 Mr. Leonard’s average maximum annual bonus opportunity under the Annual 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 $1,350,276.
(3)	In the event of a qualifying 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 product of 2.99 times the sum of his (a) annual base salary plus (b) his target Annual Incentive Plan award for any fiscal year (other than the fiscal year in which his date of termination occurs) ending after the effective date of his retention agreement.

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(4)	In the event of a qualifying 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 2008-2010 Performance Unit Program (16,500 units) and the 2009-2011Performance Unit Program (22,500 units). This average number of units (19,500 units) multiplied by the closing price of Entergy common stock on December 31, 2012 ($63.75) would equal a severance payment of $1,243,125 for the forfeited performance units. In the event of Mr. Leonard’s death, disability or retirement not related to a change in control, Mr. Leonard would not have forfeited his performance units for all open performance period, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. 2011 - 2013 Plan – 17,333 (26,000 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 8,967 (26,900 * 12/36) performance units at target, assuming a stock price of $63.75
(5)	In the event of retirement, death, disability, or a qualifying 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 Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Mr. Leonard’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.
(6)	In the event of a qualifying termination related to a change in control, all of Mr. Leonard’s unvested restricted stock would immediately vest. In the event of Mr. Leonard’s death or disability, restrictions would lift on a pro-rated portion of his unvested restricted shares that were scheduled to become vested on the immediately following twelve -month grant date anniversary, based on the number of days worked during such twelve-month period.
(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, 2012, 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 upon voluntary resignation. Effective February 1, 2013, Mr. Leonard retired as Chairman and Chief Executive Officer.
(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. Leonard voluntarily agreed to amend his retention agreement to eliminate excise tax gross up payments.

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Under the terms of Mr. Leonard's retention agreement, Entergy Corporation 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 was entitled to 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 was material to his total compensation, unless other equitable arrangements were made;

the failure to continue to provide benefits substantially similar to those that he then enjoyed under any of the pension, savings, life insurance, medical, health and accident or disability plans, or the taking of any other action which materially reduced any of those benefits or deprived him of any material fringe benefits that he then enjoyed;

·	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, 2012:

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)	---	---	---	---	---	---	---	$505,200
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$51,000	$51,000	---	$51,000
2012-2014 Performance Unit Program	---	---	---	---	$31,875	$31,875	---	$51,000
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$46,601	$46,601	---	$129,338
Medical and Dental Benefits(6)	---	---	---	---	---	---	---	$17,076
280G Tax Gross-up(9)	---	---	---	---	---	---	---	---

(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 "2012 Pension Benefits." If Mr. McDonald's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

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(2)	In the event of a qualifying 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 the product of one time the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual 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 $336,800 was assumed.
(3)	In the event of a qualifying termination related to a change in control, Mr. McDonald would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, 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. McDonald’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $ $51,000 for the forfeited performance units. In the event of Mr. McDonald’s death or disability not related to a change in control, Mr. McDonald would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. For purposes of the table, the value of Mr. McDonald’s awards were calculated as follows: 2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of his death, disability or a change in control, all of Mr. McDonald's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. McDonald’s unvested stock options granted on or after December 30, 2010 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, 2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. McDonald’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.
(5)	In the event of his death or disability, Mr. McDonald would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. McDonald would immediately vest in all unvested restricted stock.
(6)	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.

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(7)	As of December 31, 2012, compensation and benefits available to Mr. McDonald under this scenario are substantially the same as available with a voluntary resignation.
(8)	With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, 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 on or after December 30, 2010 require a qualifying 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.

William M. Mohl

President & CEO, Entergy Gulf States Louisiana and 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, 2012:

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)	---	---	---	---	---	---	---	$1,095,200
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$106,271	$106,271	---	$108,375
2012-2014 Performance Unit Program	---	---	---	---	$51,000	$51,000	---	$108,375
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$55,208	$55,208	---	$152,169
Medical and Dental Benefits(6)	---	---	---	---	---	---	---	$19,063
280G Tax Gross-up(9)	---	---	---	---	---	---	---	---

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(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 "2012 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 qualifying 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 the product of two times the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual 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 $342,250 was assumed.
(3)	In the event of a qualifying termination related to a change in control, Mr. Mohl would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, 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. Mohl’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (1,400 units) and the 2009-2011 Performance Unit Program (2,000 units). This average number of units (1,700 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $108,375 for the forfeited performance units. In the event of Mr. Mohl’s death or disability not related to a change in control, Mr. Mohl would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. For purposes of the table, the value of Mr. Mohl's awards were calculated as follows: 2011 - 2013 Plan – 1,667 (2,500 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 800 (2,400 * 12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of his death, disability or a change in control, all of Mr. Mohl's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Mohl’s unvested stock options granted on or after December 30, 2010 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, 2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Mohl’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.

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(5)	In the event of his death or disability, Mr. Mohl would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Mohl would immediately vest in all unvested restricted stock.
(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, 2012, compensation and benefits available to Mr. Mohl under this scenario are substantially the same as available with a voluntary resignation.
(8)	With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, 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 on or after December 30, 2010 require a qualifying 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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Alyson M. Mount

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 her employment under various scenarios as of December 31, 2012:

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)	---	---	---	---	---	---	---	$756,000
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$56,036	$56,036	---	$78,476
2012-2014 Performance Unit Program	---	---	---	---	$43,924	$43,924	---	$78,476
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$46,474	$46,474	---	$133,388
Medical and Dental Benefits(6)	---	---	---	---	---	---	---	$8,518
280G Tax Gross-up(9)	---	---	---	---	---	---	---	---

(1)

In addition to the payments and benefits in the table, if Ms. Mount's employment were terminated under certain conditions relating to a change in control, Ms. Mount 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 "2012 Pension Benefits." If Ms. Mount's employment were terminated for cause, she would forfeit her benefit under the System Executive Retirement Plan.

(2)

In the event of a qualifying termination related to a change in control, Ms. Mount would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 2.00 times the sum of (a) her annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) her annual incentive, calculated using the average annual target opportunity under the Annual 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 35% target opportunity and a base salary of $280,000 was assumed.

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(3)	In the event of a qualifying termination related to a change in control, Ms. Mount would have forfeited her performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units she 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 her termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Ms. Mount’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (739 units) and the 2009-2011 Performance Unit Program (1,722 units). This average number of units (1,231 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $78,476 for the forfeited performance units. In the event of Ms. Mount’s death or disability not related to a change in control, Ms. Mount would not have forfeited her performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on her number of months of participation in each open 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. For purposes of the table, the value of Ms. Mount's awards were calculated as follows: 2011 - 2013 Plan – 879 (1,319 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 689 (2,067 *12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of death, disability or a change in control, all of Ms. Mount's unvested stock options granted prior to December 30, 2010 would immediately vest In the event of her death, disability or qualifying termination related to a change in control, all of Ms. Mount’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, she 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 Ms. Mount exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Ms. Mount’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.
(5)	In the event of her death or disability, Ms. Mount would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of her death or Disability. In the event of her qualifying termination related to a change in control, Ms. Mount would immediately vest in all unvested restricted stock.
(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Mount would be eligible to receive Company- subsidized COBRA benefits for 18 months.
(7)	As of December 31, 2012, compensation and benefits available to Ms. Mount under this scenario are substantially the same as available with a voluntary resignation.

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(8)

With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, 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 a qualifying 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.

Sallie T. Rainer

President & CEO, Entergy Texas

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President & CEO, Entergy Texas would have been entitled to receive as a result of a termination of her employment under various scenarios as of December 31, 2012:

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)	---	---	---	---	---	---	---	$357,500
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$26,903	$26,903	---	$36,465
2012-2014 Performance Unit Program	---	---	---	---	$27,476	$27,476	---	$36,465
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$37,931	$37,931	---	$110,628
Medical and Dental Benefits(6)	---	---	---	---	---	---	---	$17,076
280G Tax Gross-up(9)	---	---	---	---	---	---	---	---

(1)

In addition to the payments and benefits in the table, if Ms. Rainer's employment were terminated under certain conditions relating to a change in control, Ms. Rainer 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 "2012 Pension Benefits." If Ms. Rainer's employment were terminated for cause, she would forfeit her benefit under the System Executive Retirement Plan.

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(2)	In the event of a qualifying termination related to a change in control, Ms. Rainer would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 1.00 times the sum of (a) her annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) her annual incentive, calculated using the average annual target opportunity under the Annual 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 30% target opportunity and a base salary of $275,000 was assumed.
(3)	In the event of a qualifying termination related to a change in control, Ms. Rainer would have forfeited her performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units she 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 her termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Ms. Rainer’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (369 units) and the 2009-2011 Performance Unit Program (775 units). This average number of units (572 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $36,465 for the forfeited performance units. In the event of Ms. Rainer’s death or disability not related to a change in control, Ms. Rainer would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on her number of months of participation in each open 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. For purposes of the table, the value of Ms. Rainer's awards were calculated as follows: 2011 - 2013 Plan – 422 (633 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 431 (1,292 * 12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of death, disability or a change in control, all of Ms. Rainer's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of her death, disability or qualifying termination related to a change in control, all of Ms. Rainer’s unvested stock options granted on or after December 30, 2010 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 Ms. Rainer exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Ms. Rainer’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.
(5)	In the event of his death or disability, Ms. Rainer would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of her death or Disability. In the event of her qualifying termination related to a change in control, Ms. Rainer would immediately vest in all unvested restricted stock.
(6)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Rainer would be eligible to receive Company- subsidized COBRA benefits for 12 months.

(7)	As of December 31, 2012, compensation and benefits available to Ms. Rainer under this scenario are substantially the same as available with a voluntary resignation.

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(8)

· All unvested stock options would become immediately exercisable; and

· Severance benefits in place of performance units become payable as described in footnote 3 above.

(9)

In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments.

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, 2012:

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)	---	---	---	---	---	---	---	$352,940
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$51,000	$51,000	---	$51,000
2012-2014 Performance Unit Program	---	---	---	---	$31,875	$31,875	---	$51,000
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$36,019	$36,019	---	$100,905
Medical and Dental Benefits(6)	---	---	---	---	---	---	---	$900
280G Tax Gross-up(9)	---	---	---	---	---	---	---	---

(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 "2012 Pension Benefits." If Mr. Rice's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan.

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(2)	In the event of a qualifying 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 the product of one time the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual 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 $252,100 was assumed.
(3)	In the event of a qualifying termination related to a change in control, Mr. Rice would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, 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. Rice’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $ $51,000 for the forfeited performance units. In the event of Mr. Rice’s death or disability not related to a change in control, Mr. Rice would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. For purposes of the table, the value of Mr. Rice’s awards were calculated as follows: 2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of his death, disability or a change in control, all of Mr. Rice's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Rice’s unvested stock options granted on or after December 30, 2010 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, 2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Rice’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.

(5)

In the event of his death or disability, Mr. Rice would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Rice would immediately vest in all unvested restricted stock.

(6)

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.

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(7)	As of December 31, 2012, compensation and benefits available to Mr. Rice under this scenario are substantially the same as available with a voluntary resignation.
(8)	With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, 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 on or after December 30, 2010 require a qualifying 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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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, 2012:

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)	---	---	---	---	---	---	---	$2,994,700
Performance Units:(3)
2011-2013 Performance Unit Program	---	---	---	---	$250,729	$250,729	---	$277,313
2012-2014 Performance Unit Program	---	---	---	---	$114,750	$114,750	---	$277,313
Unvested Stock Options(4)	---	---	---	---	$0	$0	---	$0
Unvested Restricted Stock(5)	---	---	---	---	$148,601	$148,601	---	$408,786
Unvested Restricted Units(6)	---	---	$956,250	---	---	---	$956,250	$956,250
Medical and Dental Benefits(7)	---	---	---	---	---	---	---	$25,614
280G Tax Gross-up(10)	---	---	---	---	---	---	---	---

(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 "2012 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 qualifying 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 the product of 2.99 times the sum of (a) his annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity under the Annual 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 70% target opportunity and a base salary of $589,160 was assumed.

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(3)	In the event of a qualifying termination related to a change in control, Mr. West would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, 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. West’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (3,900 units) and the 2009-2011 Performance Unit Program (4,800 units). This average number of units (4,350 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $277,313 for the forfeited performance units. In the event of Mr. West’s death or disability not related to a change in control, Mr. West would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open 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. For purposes of the table, the value of Mr. West's awards were calculated as follows: 2011 - 2013 Plan – 3,933 (5,900 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 1,800 (5,400 *12/36) performance units at target, assuming a stock price of $63.75
(4)	In the event of death, disability or a change in control, all of Mr. West's unvested stock options granted prior to December 30, 2010 would immediately vest In the event of his death, disability or qualifying termination related to a change in control, all of Mr. West’s unvested stock options granted on or after December 30, 2010 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. West exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Mr. West’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table.
(5)	In the event of his death or disability, Mr. West would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. West would immediately vest in all unvested restricted stock.
(6)	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.
(7)	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.
(8)	As of December 31, 2012, compensation and benefits available to Mr. West under this scenario are substantially the same as available with a voluntary resignation.

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(9)

· All unvested stock options would become immediately exercisable; and

· Severance benefits in place of performance units become payable as described in footnote 3 above.

(10)

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 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.

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 or her 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.

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;

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·	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 plans will become fully vested upon a Change in Control and the executive is involuntarily terminated without cause or terminates employment for good reason. In 2010, Entergy Corporation eliminated tax gross up payments for any severance benefits paid under the System Executive Continuity Plan.

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, shares of restricted stock 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 Annual Incentive Plan. If the officer resigns after the completion of an Annual 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 Annual 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.

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.

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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 Annual 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 12 months of participation are pro-rated based on the actual full months of participation, 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 Annual Incentive Plan and the Performance Unit Program, respectively. Unvested stock options issued under the equity ownership plans vest on the retirement date and expire ten years from the grant date of the options. Any restricted stock units held (other than those issued under the Performance Unit Program) by the executive upon his or her retirement are forfeited, and perquisites 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," including:

·	all unvested stock options will vest immediately;

·	vested stock options will expire ten years from the grant date; and

·	restricted units may be subject to specific death benefits depending on the restricted stock unit agreement (as noted, where applicable, in the tables above).

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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.

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 January 31, 2013 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*	4,943	-	9,600
Leo P. Denault**	26,725	351,662	-
Gary W. Edwards*	1,627	-	7,874
Alexis Herman*	5,777	-	7,200
Donald C. Hintz*	9,558	20,000	7,493
J. Wayne Leonard***	348,273	1,361,533	3,271
Stuart L. Levenick*	4,443	-	5,431
Blanche L. Lincoln*	1,132	-	1,000
Stewart C. Myers*	2,101	-	2,183
William A. Percy, II*	3,743	-	13,904
Mark T. Savoff**	11,590	189,333	277
Richard J. Smith**	58,657	341,600	-
W. J. Tauzin*	4,343	-	5,293
Roderick K. West**	13,813	55,334	-
Steven V. Wilkinson*	5,498	-	6,827
All directors and executive
officers as a group (20 persons)	551,535	2,617,812	70,353

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Name	Shares (1)	Options Exercisable Within 60 Days	Stock Units (2)

Entergy Arkansas
Theodore H. Bunting, Jr.***	9,607	70,233	-
Leo P. Denault***	26,725	351,662	-
J. Wayne Leonard**	348,273	1,361,533	3,271
Hugh T. McDonald***	13,042	49,066	-
Alyson M. Mount**	5,507	31,400	-
Mark T. Savoff*	11,590	189,333	277
Roderick K. West**	13,813	55,334	-
All directors and executive
officers as a group (10 persons)	462,755	2,305,278	3,548

Entergy Gulf States Louisiana
Theodore H. Bunting, Jr.***	9,607	70,233	-
Leo P. Denault***	26,725	351,662	-
J. Wayne Leonard**	348,273	1,361,533	3,271
William M. Mohl***	6,292	43,833	-
Alyson M. Mount**	5,507	31,400	-
Mark T. Savoff*	11,590	189,333	277
Roderick K. West**	13,813	55,334	-
All directors and executive
officers as a group (10 persons)	456,005	2,300,045	3,548

Entergy Louisiana
Theodore H. Bunting, Jr.***	9,607	70,233	-
Leo P. Denault***	26,725	351,662	-
J. Wayne Leonard**	348,273	1,361,533	3,271
William M. Mohl***	6,292	43,833	-
Alyson M. Mount**	5,507	31,400	-
Mark T. Savoff*	11,590	189,333	277
Roderick K. West**	13,813	55,334	-
All directors and executive
officers as a group (10 persons)	456,005	2,300,045	3,548

Entergy Mississippi
Theodore H. Bunting, Jr.***	9,607	70,233	-
Leo P. Denault***	26,725	351,662	-
Haley R. Fisackerly***	4,714	24,766	-
J. Wayne Leonard**	348,273	1,361,533	3,271
Alyson M. Mount**	5,507	31,400	-
Mark T. Savoff*	11,590	189,333	277
Roderick K. West**	13,813	55,334	-
All directors and executive
officers as a group (9 persons)	447,260	2,197,845	3,548

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Name	Shares (1)	Options Exercisable Within 60 Days	Stock Units (2)
Entergy New Orleans
Theodore H. Bunting, Jr.***	9,607	70,233	-
Leo P. Denault***	26,725	351,662	-
J. Wayne Leonard**	348,273	1,361,533	3,271
Alyson M. Mount**	5,507	31,400	-
Charles L. Rice, Jr.***	3,473	3,466	-
Mark T. Savoff*	11,590	189,333	277
Roderick K. West**	13,813	55,334	-
All directors and executive
officers as a group (9 persons)	446,019	2,176,545	3,548

Entergy Texas
Theodore H. Bunting, Jr.***	9,607	70,233	-
Leo P. Denault***	26,725	351,662	-
Joseph F. Domino**	2,650	59,966	-
J. Wayne Leonard**	348,273	1,361,533	3,271
Alyson M. Mount**	5,507	31,400	-
Sallie T. Rainer***	5,077	14,900	-
Mark T. Savoff*	11,590	189,333	277
Roderick K. West**	13,813	55,334	-
All directors and executive
officers as a group (10 persons)	450,273	2,247,945	3,548

*	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 have deferred receipt of some of their quarterly stock grants. The deferred shares will be settled in cash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period.

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Equity Compensation Plan Information

The following table summarizes the equity compensation plan information as of December 31, 2012. 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)	9,413,476	$80.32	6,081,969
Equity compensation plans not approved by security holders(2)	144,870	$44.45	-
Total	9,558,346	$79.77	6,081,969

(1)

Includes the Equity Ownership Plan, which was approved by the shareholders on May 15, 1998, the 2007 Equity Ownership Plan and the 2011 Equity Ownership Plan. The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 7,000,000 shares of Entergy Corporation common stock can be issued, with no more than 2,000,000 shares available for non-option grants. The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and 5,500,000 shares of Entergy Corporation common stock can be issued from the 2011 Equity Ownership Plan, with no more than 2,000,000 shares available for incentive stock option grants. The Equity Ownership Plan, the 2007 Equity Ownership Plan and the 2011 Equity Ownership 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 Entergy Corporation. 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, 2011, 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:

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·	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 Corporation

(a) 1 --	Merger Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC, ITC Holdings Corp. and Ibis Transaction Subsidiary LLC (2.1 to Form 8-K filed December 6, 2011 in 1-11299).

(a) 2 --	Amendment No. 1, dated as of September 21, 2012, to the Merger Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC, ITC Holdings Corp. and ITC Midsouth LLC (formerly known as Ibis Transaction Subsidiary LLC) (included in Annex A to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Corporation agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.)

(a) 3 --	Amendment No. 2, dated as of January 28, 2013, to the Merger Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC, ITC Holdings Corp. and ITC Midsouth LLC (formerly known as Ibis Transaction Subsidiary LLC) (included in Annex A to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)).

(a) 4 --	Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (2.2 to Form 8-K filed December 6, 2011 in 1-11299).

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(a) 5 --

Amendment No. 1, dated as of September 24, 2012, to the Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (included in Annex B to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Corporation agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.)

Entergy Gulf States Louisiana

(b) 1 --	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).

(b) 2 --	Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (2.2 to Form 8-K filed December 6, 2011 in 1-11299).

(b) 3 --	Amendment No. 1, dated as of September 24, 2012, to the Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (included in Annex B to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Gulf States Louisiana agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.)

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas

(c) 1 --	Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (2.2 to Form 8-K filed December 6, 2011 in 1-11299).

(c) 2 --	Amendment No. 1, dated as of September 24, 2012, to the Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (included in Annex B to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.)

(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).

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(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 --	Articles of Amendment and Restatement for the 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).

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).

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(h) 2 --

Bylaws 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 March 9, 2012, among Entergy Corporation, as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, Bank of the West, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, National Cooperative Services Corporation, and The Northern Trust Company), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.1 to Form 8-K filed March 14, 2012 in 1-11299).

(a) 3 --	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) 4 --	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) 5 --	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).

(a) 6 --	Officer’s Certificate for Entergy Corporation relating to 4.70% Senior Notes due January 15, 2017 (4.02 to Form 8-K filed January 13, 2012 in 1-11299).

System Energy

(b) 1 --

Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-four 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); 4(b) to Form 10-Q for the quarter ended September 30, 2007 in 1-9067 (Twenty-third); and 4.42 to Form 8-K dated September 25, 2012 in 1-9067 (Twenty-fourth)).

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(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).

Entergy Arkansas

Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by seventy-two 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); 4.06 to Form 8-K dated November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K dated December 13, 2012 in 1-10764 (Seventy-first); and 4(e) to Form 8-K dated January 9, 2013 in 1-10764 (Seventy-second)).

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Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Arkansas, Inc., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.2 to Form 8-K filed March 14, 2012 in 1-10764).

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)).

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(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 --	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).

(d) 5 --	Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Gulf States Louisiana, L.L.C., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.3 to Form 8-K filed March 14, 2012 in 0-20371).

Entergy Louisiana

(e) 1 --

Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by seventy-six 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); 4.08 to Form 8-K dated November 23, 2010 in 1-32718 (Seventieth); 4.08 to Form 8-K dated March 24, 2011 in 1-32718 (Seventy-first); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K dated December 15, 2011 in 1-32718 (Seventy-third); 4.08 to Form 8-K dated January 12, 2012 in 1-32718 (Seventy-fourth); 4.08 to Form 8-K dated July 3, 2012 in 1-32718 (Seventy-fifth); and 4.08 to Form 8-K dated December 4, 2012 in 1-32718 (Seventy-sixth)).

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(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).

(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 March 9, 2012, among Entergy Louisiana, LLC, as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.4 to Form 8-K filed March 14, 2012 in 1-32718).

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Entergy Mississippi

(f) 1 --

Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by thirty 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); 4(b) to Form 10-Q for the quarter ended March 31, 2010 in 1-31508 (Twenty-seventh); 4.38 to Form 8-K dated April 15, 2011 in 1-31508 (Twenty-eighth); 4.38 to Form 8-K dated May 13, 2011 in 1-31508 (Twenty-ninth); and 4.38 to Form 8-K dated December 11, 2012 in 1-31508 (Thirtieth)).

Entergy New Orleans

(g) 1 --

Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by sixteen 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); 4.02 to Form 8-K dated November 23, 2010 in 0-5807 (Fifteenth); and 4.02 to Form 8-K dated November 29, 2012 in 0-5807 (Sixteenth)).

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Entergy Texas

(h) 1 --	Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Texas, Inc., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.5 to Form 8-K filed March 14, 2012 in 1-34360).

(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).

(h) 7 --	Officer’s Certificate No. 5-B-4 dated September 7, 2011, 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 (4.40 to Form 8-K dated September 13, 2011 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).

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(a) 3 --	Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080).

(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 January 1, 2011, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 2011 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-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee.

(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-seventh Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2012, among Entergy Corporation, System Energy, and The Bank of New York Mellon, as successor trustee.

(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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Table of Contents

(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 --	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 filed on March 24, 2006 in 1-11299).

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+(a) 47 --	First Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective October 26, 2006 (10(a)50 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 48 --	Second Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective January 1, 2009 (10(a)51 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 49 --	Third Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective December 30, 2010 (10(a)52 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 50 --	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) 51 --	First Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2005 (10(a)54 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 52 --	Second Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective October 26, 2006 (10(a)55 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 53 --	Third Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)56 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 54 --	2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2011 in 1-11299).

+(a) 55 --	Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)57 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 56 --	First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)58 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 57 --	Second Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)57 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 58 --	Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)59 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 59 --	First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)60 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 60 --	Second Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)60 to Form 10-K for the year ended December 31, 2011 in 1-11299).

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+(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 (10(a)62 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 63 --	First Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)63 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 64 --	Second Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)64 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 65 --	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) 66 --	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) 67 --	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) 68 --	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) 69--	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) 70 --	Second Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)69 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 71 --	Third Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)71 to Form 10-K for the year ended December 31, 2011 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 (10(a)74 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 75 --	First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)75 to Form 10-K for the year ended December 31, 2010 in 1-11299).

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+(a) 76 --	Second Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)76 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 77 --	Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, as amended and restated effective June 1, 2012 (10(a) to Form 10-Q for the quarter ended September 30, 2012 in 1-11299).

+(a) 78 --	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) 79 --	System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)78 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 80 --	First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)79 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 81 --	Second Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)81 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 82 --	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) 83 --	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) 84 --	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) 85 --	Amendment to Retention Agreement effective January 1, 2009 between J. Wayne Leonard and Entergy Corporation (10(a)83 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 86 --	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) 87 --	Amendment to Retention Agreement effective December 30, 2010 between J. Wayne Leonard and Entergy Corporation (10(a)85 to Form 10-K for the year ended December 31, 2010 in 1-11299).

(a) 88 --	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) 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).

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Table of Contents

+(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 (10(a)93 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(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).

+(a) 95 --	Amendment to Retention Agreement effective December 30, 2010 between Leo P. Denault and Entergy Corporation (10(a)95 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(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 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended June 30, 2011 in 1-11299).

+(a) 98 --	First Amendment to Entergy Corporation Outside Director Stock Program Established under the 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation Subsidiaries (10(b) to Form 10-Q for the quarter ended September 30, 2012 in 1-11299).

+(a) 99 --	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) 100 --	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) 101 --	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 filed on March 17, 2010 in 1-11299).

+(a) 102 --	First Amendment of the Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)106 to Form 10-K for the year ended December 31, 2011 in 1-11299).

*+(a)103--	Form of Stock Option Grant Letter.

*+(a)104--	Form of Long Term Incentive Program Performance Unit Grant Letter.

*+(a)105--	Form of Restricted Stock Grant Letter.

(a) 106 --	Employee Matters Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC and ITC Holdings Corp. (10.1 to Form 8-K filed December 6, 2011 in 1-11299).

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Table of Contents

*+(a)107--

Restricted Unit Agreement between Joseph F. Domino and Entergy Corporation.

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).

(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).

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Table of Contents

(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).

(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).

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(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).

(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 January 1, 2011, to Service Agreement with Entergy Services (10(b)46 to Form 10-K for the year ended December 31, 2011 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).

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*(b) 55 --

Fifth Amendment and Consent, dated as of November 15, 2012, to Letter of Credit and Reimbursement Agreement.

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).

(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 January 1, 2011, to Service Agreement with Entergy Services (10(c)7 to Form 10-K for the year ended December 31, 2011 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).

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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).

(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).

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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).

(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).

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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).

(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).

(c) 66 --	Loan Agreement, dated as of January 1, 2013, between Jefferson County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(b) to Form 8-K filed January 9, 2013 in 1-10764).

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Loan Agreement, dated as of January 1, 2013, between Independence County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(d) to Form 8-K filed January 9, 2013 in 1-10764).

Entergy Gulf States Louisiana

(d) 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).

(d) 2 --	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) 3 --	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) 4 --	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) 5 --	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) 6 --	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) 7 --	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) 8 --	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) 9 --	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).

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+(d) 10 --	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).

+(d) 11 --	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) 12 --	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) 13 --	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) 14 --	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) 15 --	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) 16 --	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) 17 --	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) 18 --	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) 19 --	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) 20 --	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).

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+(d) 21 --

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) 22 --	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).

+(d) 23 --	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) 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).

(d) 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).

(d) 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 0-20371).

(d) 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 0-20371).

(d) 28 --	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) 29 --	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) 30 --	Amendment, dated January 1, 2011, to Service Agreement with Entergy Services (10(d)30 to Form 10-K for the year ended December 31, 2011 in 0-20371).

(d) 31 --	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) 32 --	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) 33 --	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) 34 --	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) 35 --	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) 36 --	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) 37 --	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 January 1, 2011, to Service Agreement with Entergy Services (10(e)7 to Form 10-K for the year ended December 31, 2011 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 January 1, 2011, to Service Agreement with Entergy Services (10(f)7 to Form 10-K for the year ended December 31, 2011 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).

(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).

E-30

Table of Contents

(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).

(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).

E-31

Table of Contents

(g) 7 --

Amendment, dated January 1, 2011, to Service Agreement with Entergy Services (10(g)7 to Form 10-K for the year ended December 31, 2011 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).

(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).

E-32

Table of Contents

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).

+(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).

E-33

Table of Contents

+(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 January 1, 2011, to Service Agreement with Entergy Services (10(h)22 to Form 10-K for the year ended December 31, 2011 in 1-34360).

(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.

E-34

Table of Contents

*(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 511.

*(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.

*(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.

E-35

Table of Contents

*(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.

*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-36

(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, 2012
	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 – 178,092,521 shares outstanding at January 31, 2013	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.
	Mortgage Bonds, 4.90% Series due December 2052	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.
	Mortgage Bonds, 5.25% Series due July 2052	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.
	Mortgage Bonds, 6.0% Series due May 2051	New York Stock Exchange, Inc.

Entergy New Orleans, Inc.	Mortgage Bonds, 5.0% Series due December 2052	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

Statements of Changes in Equity for the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	314
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	315
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	316
Report of Independent Registered Public Accounting Firm		334
Consolidated Income Statements For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	335
Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	336
Consolidated Statements of Cash Flows For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	337
Consolidated Balance Sheets, December 31, 2012 and 2011	Part II. Item 8.	338
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	340
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	341
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	342
Report of Independent Registered Public Accounting Firm		353
Income Statements For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	354
Statements of Cash Flows For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	355
Balance Sheets, December 31, 2012 and 2011	Part II. Item 8.	356
Statements of Changes in Common Equity for the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	358
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	359
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	360
Report of Independent Registered Public Accounting Firm		371
Income Statements For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	372
Statements of Cash Flows For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	373
Balance Sheets, December 31, 2012 and 2011	Part II. Item 8.	374
Statements of Changes in Common Equity for the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	376
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	377
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	378
Report of Independent Registered Public Accounting Firm		389
Consolidated Income Statements For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	390
Consolidated Statements of Cash Flows For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	391
Consolidated Balance Sheets, December 31, 2012 and 2011	Part II. Item 8.	392
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	394
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	395
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	396
Report of Independent Registered Public Accounting Firm		403

	SEC Form 10-K Reference Number	Page Number

Forward-looking information		iv
Definitions		vii
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	1
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	48
Report of Independent Registered Public Accounting Firm		49
Consolidated Income Statements For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	50
Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	51
Consolidated Statements of Cash Flows For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	52
Consolidated Balance Sheets, December 31, 2012 and 2011	Part II. Item 8.	54
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	56
Notes to Financial Statements	Part II. Item 8.	57
Entergy’s Business	Part I. Item 1.	205
Utility	Part I. Item 1.	205
Entergy Wholesale Commodities	Part I. Item 1.	224
Regulation of Entergy’s Business	Part I. Item 1.	229
Litigation		244
Employees		246
Availability of SEC filings and other information on Entergy’s website		246
Risk Factors	Part I. Item 1A.	247
Unresolved Staff Comments	Part I. Item 1B.	None
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	269
Report of Independent Registered Public Accounting Firm		283
Consolidated Income Statements For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	284
Consolidated Statements of Cash Flows For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	285
Consolidated Balance Sheets, December 31, 2012 and 2011	Part II. Item 8.	286
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	288
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	289
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis	Part II. Item 7.	290
Report of Independent Registered Public Accounting Firm		308
Income Statements For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	309
Statements of Comprehensive Income For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	310
Statements of Cash Flows For the Years Ended December 31, 2012, 2011, and 2010	Part II. Item 8.	311
Balance Sheets, December 31, 2012 and 2011	Part II. Item 8.	312

Abbreviation or Acronym	Term

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
ASLB	Atomic Safety and Licensing Board, the board within the NRC that conducts hearings and performs other regulatory functions that the NRC authorizes
ASU	Accounting Standards Update issued by the FASB
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 Circuit
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 (EWC)	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

Abbreviation or Acronym	Term

Ritchie Unit 2	Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil)
River Bend	River Bend Station (nuclear), owned by Entergy Gulf States Louisiana
RTO	Regional transmission organization
SEC	Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association, which owns a 10% interest in Grand Gulf
System Agreement	Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources
System Energy	System Energy Resources, Inc.
System Fuels	System Fuels, Inc.
TWh	Terawatt-hour(s), which equals one billion kilowatt-hours
U.K.	United Kingdom of Great Britain and Northern Ireland
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	2012	2011	2010	2012	2011	2010	2012	2011	2010

Utility	78	79	78	110	82	65	82	80	80
Entergy Wholesale Commodities	22	21	22	5	36	36	22	24	26
Parent & Other	-	-	-	(15)	(18)	(1)	(4)	(4)	(6)

	2012	2011

Owned capacity	6,612	6,599
GWh billed	46,178	43,497
Average realized price per MWh	$50.02	$54.50

Entergy Wholesale Commodities Nuclear Fleet
Capacity factor	89%	93%
GWh billed	41,042	40,918
Average realized revenue per MWh	$50.29	$54.73
Refueling Outage Days:
FitzPatrick	34	-
Indian Point 2	28	-
Indian Point 3	-	30
Palisades	34	-
Pilgrim	-	25
Vermont Yankee	-	25

Long-term debt maturities and estimated interest payments	2013	2014	2015	2016-2017	after 2017
	(In Millions)

Utility	$1,194	$904	$816	$1,540	$12,186
Entergy Wholesale Commodities	15	15	18	4	57
Parent and Other	83	83	627	1,385	512
Total	$1,292	$1,002	$1,461	$2,929	$12,755

Capacity	Borrowings	Letters of Credit	Capacity Available
(In Millions)

$3,500	$795	$8	$2,697

Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of Dec. 31, 2012

Entergy Arkansas	April 2013	$20 million (b)	1.81%	-
Entergy Arkansas	March 2017	$150 million (c)	1.71%	-
Entergy Gulf States Louisiana	March 2017	$150 million (d)	1.71%	-
Entergy Louisiana	March 2017	$200 million (e)	1.71%	-
Entergy Mississippi	May 2013	$35 million (f)	1.96%	-
Entergy Mississippi	May 2013	$25 million (f)	1.96%	-
Entergy Mississippi	May 2013	$10 million (f)	1.96%	-
Entergy New Orleans	November 2013	$25 million (g)	1.69%	-
Entergy Texas	March 2017	$150 million (f)	1.96%	-

(a)	The interest rate is the weighted average interest rate as of December 31, 2012 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 this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable.
(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, no letters of credit were outstanding. The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of 65% or less of its total capitalization.
(d)	The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, 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.
(e)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, 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.
(f)	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.
(g)	The credit facility requires Entergy New Orleans to maintain a debt ratio of 65% or less of its total capitalization.
(h)	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, 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.

Contractual Obligations	2013	2014-2015	2016-2017	after 2017	Total
	(In Millions)

Long-term debt (1)	$1,292	$2,463	$2,929	$12,755	$19,439
Capital lease payments (2)	$6	$10	$9	$34	$59
Operating leases (2)	$94	$177	$94	$140	$505
Purchase obligations (3)	$1,939	$3,512	$2,609	$11,195	$19,255

(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.

Company		Authorized Return on Common Equity

Entergy Arkansas		10.2%

Entergy Gulf States Louisiana		9.9%-11.4% Electric; 10.0%-11.0% Gas

Entergy Louisiana		9.45% - 11.05%

Entergy Mississippi		9.88% - 12.01%

Entergy New Orleans		10.7% - 11.5% Electric; 10.25% - 11.25% Gas

Entergy Texas		9.8%

(b)	Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages.
(c)	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.
(d)	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, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products.
(e)	Transactions for the purchase of energy, generally to offset a firm LD transaction.
(f)	Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch.
(g)	Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above.
(h)	Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.
(i)	A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.
(j)	A contract for the sale of an installed capacity product in a regional market.
(k)	Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year.
(l)	Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which do not operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2.
(m)	Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate.

Actuarial Assumption	Change in Assumption	Impact on 2012 Qualified Pension Cost	Impact on Qualified Projected Benefit Obligation
	Increase/(Decrease)

Discount rate	(0.25%)	$20,142	$229,473
Rate of return on plan assets	(0.25%)	$9,337	$-
Rate of increase in compensation	0.25%	$8,512	$48,036

LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation	ANDREW S. MARSH 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.	PHILLIP R. MAY, JR. 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. Chairman of the Board, President and Chief Executive Officer of Entergy New Orleans, Inc.
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc.	JEFFREY S. FORBES Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc.
ALYSON M. MOUNT 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,
	2012			2011			2010
	(In Thousands, Except Share Data)

OPERATING REVENUES
Electric	$	7,870,649		$	8,673,517		$	8,740,637
Natural gas		130,836			165,819			197,658
Competitive businesses		2,300,594			2,389,737			2,549,282
TOTAL		10,302,079			11,229,073			11,487,577

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel-related expenses, and
gas purchased for resale		2,036,835			2,492,714			2,518,582
Purchased power		1,255,800			1,564,967			1,659,416
Nuclear refueling outage expenses		245,600			255,618			256,123
Asset impairment		355,524			-			-
Other operation and maintenance		3,045,392			2,867,758			2,969,402
Decommissioning		184,760			190,595			211,736
Taxes other than income taxes		557,298			536,026			534,299
Depreciation and amortization		1,144,585			1,102,202			1,069,894
Other regulatory charges - net		175,104			205,959			44,921
TOTAL		9,000,898			9,215,839			9,264,373

Gain on sale of business		-			-			44,173

OPERATING INCOME		1,301,181			2,013,234			2,267,377

OTHER INCOME
Allowance for equity funds used during construction		92,759			84,305			59,381
Interest and investment income		127,776			128,994			184,077
Miscellaneous - net		(53,214	)		(59,271	)		(48,124	)
TOTAL		167,321			154,028			195,334

INTEREST EXPENSE
Interest expense		606,596			551,521			610,146
Allowance for borrowed funds used during construction		(37,312	)		(37,894	)		(34,979	)
TOTAL		569,284			513,627			575,167

INCOME BEFORE INCOME TAXES		899,218			1,653,635			1,887,544

Income taxes		30,855			286,263			617,239

CONSOLIDATED NET INCOME		868,363			1,367,372			1,270,305

Preferred dividend requirements of subsidiaries		21,690			20,933			20,063

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	846,673		$	1,346,439		$	1,250,242


Earnings per average common share:
Basic	$	4.77		$	7.59		$	6.72
Diluted	$	4.76		$	7.55		$	6.66
Dividends declared per common share	$	3.32		$	3.32		$	3.24

Basic average number of common shares outstanding		177,324,813			177,430,208			186,010,452
Diluted average number of common shares outstanding		177,737,565			178,370,695			187,814,235

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2012			2011			2010
	(In Thousands)

OPERATING ACTIVITIES
Consolidated net income	$	868,363		$	1,367,372		$	1,270,305
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		1,771,649			1,745,455			1,705,331
Deferred income taxes, investment tax credits, and non-current taxes accrued		(26,479	)		(280,029	)		718,987
Asset impairment		355,524			-			-
Gain on sale of business		-			-			(44,173	)
Changes in working capital:
Receivables		(14,202	)		28,091			(99,640	)
Fuel inventory		(11,604	)		5,393			(10,665	)
Accounts payable		(6,779	)		(131,970	)		216,635
Prepaid taxes and taxes accrued		55,484			580,042			(116,988	)
Interest accrued		1,152			(34,172	)		17,651
Deferred fuel costs		(99,987	)		(55,686	)		8,909
Other working capital accounts		(151,989	)		41,875			(160,326	)
Changes in provisions for estimated losses		(24,808	)		(11,086	)		265,284
Changes in other regulatory assets		(398,428	)		(673,244	)		339,408
Changes in pensions and other postretirement liabilities		644,099			962,461			(80,844	)
Other		(21,710	)		(415,685	)		(103,793	)
Net cash flow provided by operating activities		2,940,285			3,128,817			3,926,081

INVESTING ACTIVITIES
Construction/capital expenditures		(2,674,650	)		(2,040,027	)		(1,974,286	)
Allowance for equity funds used during construction		96,131			86,252			59,381
Nuclear fuel purchases		(557,960	)		(641,493	)		(407,711	)
Payment for purchase of plant		(456,356	)		(646,137	)		-
Proceeds from sale of assets and businesses		-			6,531			228,171
Insurance proceeds received for property damages		-			-			7,894
Changes in securitization account		4,265			(7,260	)		(29,945	)
NYPA value sharing payment		(72,000	)		(72,000	)		(72,000	)
Payments to storm reserve escrow account		(8,957	)		(6,425	)		(296,614	)
Receipts from storm reserve escrow account		27,884			-			9,925
Decrease (increase) in other investments		15,175			(11,623	)		24,956
Litigation proceeds for reimbursement of spent nuclear fuel storage costs		109,105			-			-
Proceeds from nuclear decommissioning trust fund sales		2,074,055			1,360,346			2,606,383
Investment in nuclear decommissioning trust funds		(2,196,489	)		(1,475,017	)		(2,730,377	)
Net cash flow used in investing activities		(3,639,797	)		(3,446,853	)		(2,574,223	)

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2012			2011
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$	112,992		$	81,468
Temporary cash investments		419,577			612,970
Total cash and cash equivalents		532,569			694,438
Securitization recovery trust account		46,040			50,304
Accounts receivable:
Customer		568,871			568,558
Allowance for doubtful accounts		(31,956	)		(31,159	)
Other		161,408			166,186
Accrued unbilled revenues		303,392			298,283
Total accounts receivable		1,001,715			1,001,868
Deferred fuel costs		150,363			209,776
Accumulated deferred income taxes		306,902			9,856
Fuel inventory - at average cost		213,831			202,132
Materials and supplies - at average cost		928,530			894,756
Deferred nuclear refueling outage costs		243,374			231,031
System agreement cost equalization		16,880			36,800
Prepayments and other		242,922			291,742
TOTAL		3,683,126			3,622,703

OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity		46,738			44,876
Decommissioning trust funds		4,190,108			3,788,031
Non-utility property - at cost (less accumulated depreciation)		256,039			260,436
Other		436,234			416,423
TOTAL		4,929,119			4,509,766

PROPERTY, PLANT AND EQUIPMENT
Electric		41,944,567			39,385,524
Property under capital lease		935,199			809,449
Natural gas		353,492			343,550
Construction work in progress		1,365,699			1,779,723
Nuclear fuel		1,598,430			1,546,167
TOTAL PROPERTY, PLANT AND EQUIPMENT		46,197,387			43,864,413
Less - accumulated depreciation and amortization		18,898,842			18,255,128
PROPERTY, PLANT AND EQUIPMENT - NET		27,298,545			25,609,285

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net		742,030			799,006
Other regulatory assets (includes securitization property of
$914,751 as of December 31, 2012 and $1,009,103 as of
December 31, 2011)		5,025,912			4,636,871
Deferred fuel costs		172,202			172,202
Goodwill		377,172			377,172
Accumulated deferred income taxes		37,748			19,003
Other		936,648			955,691
TOTAL		7,291,712			6,959,945

TOTAL ASSETS	$	43,202,502		$	40,701,699

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2012			2011
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$	718,516		$	2,192,733
Notes payable and commercial paper		796,002			108,331
Accounts payable		1,217,180			1,069,096
Customer deposits		359,078			351,741
Taxes accrued		333,719			278,235
Accumulated deferred income taxes		13,109			99,929
Interest accrued		184,664			183,512
Deferred fuel costs		96,439			255,839
Obligations under capital leases		3,880			3,631
Pension and other postretirement liabilities		95,900			44,031
System agreement cost equalization		25,848			80,090
Other		261,986			283,531
TOTAL		4,106,321			4,950,699

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued		8,311,756			8,096,452
Accumulated deferred investment tax credits		273,696			284,747
Obligations under capital leases		34,541			38,421
Other regulatory liabilities		898,614			728,193
Decommissioning and asset retirement cost liabilities		3,513,634			3,296,570
Accumulated provisions		362,226			385,512
Pension and other postretirement liabilities		3,725,886			3,133,657
Long-term debt (includes securitization bonds of $973,480 as of
December 31, 2012 and $1,070,556 as of December 31, 2011)		11,920,318			10,043,713
Other		577,910			501,954
TOTAL		29,618,581			26,509,219

Commitments and Contingencies

Subsidiaries' preferred stock without sinking fund		186,511			186,511

EQUITY
Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2012 and in 2011		2,548			2,548
Paid-in capital		5,357,852			5,360,682
Retained earnings		9,704,591			9,446,960
Accumulated other comprehensive loss		(293,083	)		(168,452	)
Less - treasury stock, at cost (76,945,239 shares in 2012 and
78,396,988 shares in 2011)		5,574,819			5,680,468
Total common shareholders' equity		9,197,089			8,961,270
Subsidiaries' preferred stock without sinking fund		94,000			94,000
TOTAL		9,291,089			9,055,270

TOTAL LIABILITIES AND EQUITY	$	43,202,502		$	40,701,699

See Notes to Financial Statements.

ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2012, 2011, and 2010

				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, 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		-			-		-			-			-			36,973			36,973
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


Consolidated net income (a)		20,933			-		-			-			1,346,439			-			1,367,372
Other comprehensive loss		-			-		-			-			-			(130,240	)		(130,240	)
Common stock repurchases		-			-		(234,632	)		-			-			-			(234,632	)
Common stock issuances related to stock plans		-			-		78,975			(6,792	)		-			-			72,183
Common stock dividends declared		-			-		-			-			(588,880	)		-			(588,880	)
Preferred dividend requirements of subsidiaries (a)		(20,933	)		-		-			-			-			-			(20,933	)

Balance at December 31, 2011	$	94,000		$	2,548	$	(5,680,468	)	$	5,360,682		$	9,446,960		$	(168,452	)	$	9,055,270


Consolidated net income (a)		21,690			-		-			-			846,673			-			868,363
Other comprehensive loss		-			-		-			-			-			(124,631	)		(124,631	)
Common stock issuances related to stock plans		-			-	$	105,649			(2,830	)		-			-			102,819
Common stock dividends declared		-			-		-			-			(589,042	)		-			(589,042	)
Preferred dividend requirements of subsidiaries (a)		(21,690	)		-		-			-			-			-			(21,690	)

Balance at December 31, 2012	$	94,000		$	2,548	$	(5,574,819	)	$	5,357,852		$	9,704,591		$	(293,083	)	$	9,291,089







See Notes to Financial Statements.

(a) Consolidated net income and preferred dividend requirements of subsidiaries for 2012, 2011, and 2010 include $15.0 million, $13.3 million, and $13.3 million, respectively, 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
2012	Arkansas			Louisiana			Louisiana			Mississippi			New Orleans			Texas			Energy
	(In Thousands)
Current:
Federal	$	64,069		$	(66,081	)	$	(132,999	)	$	3,188		$	(9,484	)	$	(114,677	)	$	(50,491	)
State		6,712			9,535			(1,269	)		(4,425	)		(1,617	)		4,933			(8,544	)
Total		70,781			(56,546	)		(134,268	)		(1,237	)		(11,101	)		(109,744	)		(59,035	)
Deferred and non-current - net		26,042			112,390			8,463			59,045			18,586			144,471			137,832
Investment tax credit
adjustments - net		(2,017	)		(3,228	)		(3,117	)		871			(245	)		(1,609	)		(1,682	)
Income taxes	$	94,806		$	52,616		$	(128,922	)	$	58,679		$	7,240		$	33,118		$	77,115

(a) See "Income Tax Audits - 2006-2007 IRS Audit" below for discussion of these items.
(b) See "Income Tax Audits - 2004-2005 IRS Audit" below for discussion of this item.
(c) See "Income Tax Audits - 2008-2009 IRS Audit" below for discussion of the most significant item in 2012.

Carryover Description	Carryover Amount	Year(s) of expiration

Federal net operating losses	$12.6 billion	2028-2032
State net operating losses	$11.2 billion	2013-2032
State capital losses	$177 million	2013-2015
Miscellaneous federal and state credits	$81.9 million	2013-2032

2012	Entergy Arkansas			Entergy Gulf States Louisiana			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)

Gross balance at January 1, 2012	$	335,493		$	390,493		$	446,187		$	11,052		$	56,052		$	19,225		$	281,183
Additions based on tax
positions related to the
current year		10,409			8,974			67,721			8,401			497			1,656			8,715
Additions for tax positions
of prior years		429,232			392,548			331,432			4,057			445			4,834			271,172
Reductions for tax
positions of prior years		(39,534	)		(50,518	)		(169,465	)		(5,703	)		(2,506	)		(11,649	)		(20,934	)
Settlements		(390,931	)		(275,776	)		(139,202	)		(966	)		(2,470	)		(112	)		(279,790	)
Gross balance at December 31, 2012		344,669			465,721			536,673			16,841			52,018			13,954			260,346
Offsets to gross unrecognized
tax benefits:
Loss carryovers		(342,127	)		(160,955	)		(536,673	)		(16,841	)		(35,511	)		(1,593	)		(249,424	)
Cash paid to taxing authorities		-			-			-			-			-			-			-
Unrecognized tax benefits net of
unused tax attributes and payments	$	2,542		$	304,766		$	-		$	-		$	16,507		$	12,361		$	10,922

	December 31, 2012		December 31, 2011		December 31, 2010
	(In Millions)

Entergy Arkansas	$	0.6	$	-	$	0.2
Entergy Gulf States Louisiana	$	44.0	$	107.9	$	129.6
Entergy Louisiana	$	92.4	$	281.3	$	286.7
Entergy Mississippi	$	3.9	$	3.8	$	5.3
Entergy New Orleans	$	-	$	-	$	-
Entergy Texas	$	8.6	$	7.3	$	6.0
System Energy	$	3.5	$	-	$	12.1

Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of December 31, 2012

Entergy Arkansas	April 2013	$20 million (b)	1.81%	-
Entergy Arkansas	March 2017	$150 million (c)	1.71%	-
Entergy Gulf States Louisiana	March 2017	$150 million (d)	1.71%	-
Entergy Louisiana	March 2017	$200 million (e)	1.71%	-
Entergy Mississippi	May 2013	$35 million (f)	1.96%	-
Entergy Mississippi	May 2013	$25 million (f)	1.96%	-
Entergy Mississippi	May 2013	$10 million (f)	1.96%	-
Entergy New Orleans	November 2013	$25 million (g)	1.69%	-
Entergy Texas	March 2017	$150 million (h)	1.96%	-

(a)	The interest rate is the rate as of December 31, 2012 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 this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable.
(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, no letters of credit were outstanding. The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of 65% or less of its total capitalization.

	Authorized	Borrowings
	(In Millions)

Entergy Arkansas	$250	-
Entergy Gulf States Louisiana	$200	$7
Entergy Louisiana	$250	-
Entergy Mississippi	$175	-
Entergy New Orleans	$100	-
Entergy Texas	$200	-
System Energy	$200	-

Company	Expiration Date	Amount of Facility	Weighted Average Interest Rate on Borrowings (a)	Amount Outstanding as of December 31, 2012
	(Dollars in Millions)

Entergy Arkansas VIE	July 2013	$85	2.31%	$36.7
Entergy Gulf States Louisiana VIE	July 2013	$85	n/a	$-
Entergy Louisiana VIE	July 2013	$90	2.36%	$54.7
System Energy VIE	July 2013	$100	2.37%	$40.0

Company	Description	Amount

Entergy Arkansas VIE	9% Series H due June 2013	$30 million
Entergy Arkansas VIE	5.69% Series I due July 2014	$70 million
Entergy Arkansas VIE	3.23% Series J due July 2016	$55 million
Entergy Arkansas VIE	2.62% Series K due December 2017	$60 million
Entergy Gulf States Louisiana VIE	5.56% Series N due May 2013	$75 million
Entergy Gulf States Louisiana VIE	3.25% Series Q due July 2017	$75 million
Entergy Louisiana VIE	5.69% Series E due July 2014	$50 million
Entergy Louisiana VIE	3.30% Series F due March 2016	$20 million
Entergy Louisiana VIE	3.25% Series G due July 2017	$25 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
System Energy VIE	4.02% Series H due February 2017	$50 million