ENTERGY CORP /DE/ - FORM 8-K - EX-99.1 - EARNINGS RELEASE

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8-K - FORM 8-K - ENTERGY CORP /DE/	a07810.htm
EX-99.3 - STATEMENT OF USES AND USEFULNESS OF NON-GAAP INFORMATION - ENTERGY CORP /DE/	a07810993.htm
EX-99.2 - MEDIA RELEASE - ENTERGY CORP /DE/	a07810992.htm

For further information:

Paula Waters, VP, Investor Relations

Phone 504/576-4380, Fax 504/576-2897

pwater1@entergy.com

INVESTOR NEWS

Exhibit 99.1

October 21, 2010

ENTERGY REPORTS THIRD QUARTER EARNINGS

NEW ORLEANS – Entergy Corporation (NYSE: ETR) reported third quarter 2010 earnings of $2.62 per share on an as-reported basis and $2.76 per share on an operational basis, as shown in Table 1 below. A more detailed discussion of quarterly results begins on page 2 of this release.

Table 1: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures
Third Quarter and Year-to-Date 2010 vs. 2009
(Per share in U.S. $)
	Third Quarter			Year-to-Date
	2010	2009	Change	2010	2009	Change
As-Reported Earnings	2.62	2.32	0.30	5.38	4.66	0.72

Less Special Items	(0.14)	(0.08)	(0.06)	(0.40)	(0.26)	(0.14)

Operational Earnings	2.76	2.40	0.36	5.78	4.92	0.86

Weather Impact	0.29	0.03	0.26	0.55	-	0.55

Operational Earnings Highlights for Third Quarter 2010

·	Utility’s earnings were higher primarily due to increased net revenue, which was partially offset by an increase in non-fuel operation and maintenance expense.

·	Entergy Nuclear’s earnings decreased as a result of lower net revenue, resulting from decreased generation output due to increased planned and unplanned outage days, and higher non-fuel operation and maintenance expense.

·	Parent & Other’s results improved due primarily to lower income tax expense on Parent & Other activities.

“Despite challenging times, near-record warm temperatures boosted Entergy’s third quarter earnings per share to the highest of any quarterly period in company history,” said J. Wayne Leonard, Entergy’s chairman and chief executive officer. “Even with this achievement, we continue to focus on the building blocks for delivering long-term value – safety, operational excellence, and meeting regulatory expectations – in both the Utility and Entergy Wholesale Commodities businesses as well as maintaining solid financial strength and disciplined risk management.”

Entergy’s business highlights include the following:

·	Entergy Texas reached an unopposed settlement in its base rate case, subject to approval by the Public Utility Commission of Texas, reflecting a total $68 million rate increase to be fully implemented by May 2011.

·	The J.A. FitzPatrick plant completed a record-setting “breaker to breaker” run, setting a new all-time record for the number of days of continuous operation within the Entergy fleet and seventh all-time for all boiling water reactors in the United States.

·	Reports by the New York Independent System Operator and ISO New England point to the criticality of Indian Point and Vermont Yankee to their regions.

·	For the ninth consecutive year Entergy was named to the Dow Jones Sustainability World Index.

Entergy will host a teleconference to discuss this release at 10 a.m. CT on Thursday, October 21, 2010, with access by telephone, 719-457-2080, confirmation code 5590047. The call and presentation slides can also be accessed via Entergy’s website at www.entergy.com. A replay of the teleconference will be available through October 28, 2010, by dialing 719-457-0820, confirmation code 5590047. The replay will also be available on Entergy’s website at www.entergy.com.

I.	Consolidated Results

Consolidated Earnings

Table 2 provides a comparative summary of consolidated earnings per share for third quarter and year-to-date 2010 versus 2009, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings. Utility’s earnings increased quarter-over-quarter as a result of higher net revenue due primarily to increased sales volumes across all customer classes, including significantly warmer-than-normal weather, and the effect of previous rate actions. Utility net revenue was partially offset by higher non-fuel operation and maintenance expense. Entergy Nuclear’s third quarter 2010 earnings decreased as a result of lower net revenue attributable to lower generation, resulting from additional planned and unplanned outage days, and higher non-fuel operation and maintenance expense. A lower effective tax rate provided a partial offset at Entergy Nuclear. Parent and Other’s results were higher in the current period compared to a year ago due primarily to lower income tax expense on Parent & Other activities. Entergy’s results for the current period also reflect the positive effect of accretion associated with the company’s share repurchase programs.

Table 2: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures Third Quarter and Year-to-Date 2010 vs. 2009 (see Appendix D for definitions of certain measures)
(Per share in U.S. $)
	Third Quarter			Year-to-Date
	2010	2009	Change	2010	2009	Change
As-Reported
Utility	1.78	1.50	0.28	3.68	2.80	0.88
Entergy Nuclear	0.71	1.02	(0.31)	1.83	2.34	(0.51)
Parent & Other	0.13	(0.20)	0.33	(0.13)	(0.48)	0.35
Consolidated As-Reported Earnings	2.62	2.32	0.30	5.38	4.66	0.72

Less Special Items
Utility	-	-	-	-	-	-
Entergy Nuclear	(0.14)	(0.05)	(0.09)	(0.50)	(0.17)	(0.33)
Parent & Other	-	(0.03)	0.03	0.10	(0.09)	0.19
Consolidated Special Items	(0.14)	(0.08)	(0.06)	(0.40)	(0.26)	(0.14)

Operational
Utility	1.78	1.50	0.28	3.68	2.80	0.88
Entergy Nuclear	0.85	1.07	(0.22)	2.33	2.51	(0.18)
Parent & Other	0.13	(0.17)	0.30	(0.23)	(0.39)	0.16
Consolidated Operational Earnings	2.76	2.40	0.36	5.78	4.92	0.86
Weather Impact	0.29	0.03	0.26	0.55	-	0.55

Detailed earnings variance analysis is included in Appendix A-1 and Appendix A-2 to this release. In addition, Appendix A-3 provides details of special items shown in Table 2 above.

Consolidated Net Cash Flow Provided by Operating Activities

Entergy’s net cash flow provided by operating activities in third quarter 2010 was $1,697 million compared to $993 million in third quarter 2009. The overall quarterly increase was due primarily to:

·	The receipt of $703 million of proceeds associated with storm-related debt issuances from the Louisiana Utilities Restoration Corporation for Entergy Louisiana and Entergy Gulf States Louisiana for hurricanes Gustav and Ike, and

·	Higher Utility net revenue

Partially offsetting these increases was higher working capital requirements at the Utility. In addition, intercompany tax payments contributed to line of business variances, but were largely offsetting between Utility, Entergy Nuclear, and Parent & Other.

Table 3 provides the components of net cash flow provided by operating activities contributed by each business with quarterly and year-to-date comparisons.

Table 3: Consolidated Net Cash Flow Provided by Operating Activities
Third Quarter and Year-to-Date 2010 vs. 2009
(U.S. $ in millions)
	Third Quarter			Year-to-Date
	2010	2009	Change	2010	2009	Change
Utility	1,426	642	784	2,419	1,320	1,099
Entergy Nuclear	175	337	(162)	725	709	16
Parent & Other	96	14	82	21	(20)	41
Consolidated Net Cash Flow Provided by Operating Activities	1,697	993	704	3,165	2,009	1,156

II.

Utility

In third quarter 2010, Utility’s as-reported and operational earnings were $1.78 per share compared to $1.50 per share on the same bases in third quarter 2009. The Utility earnings increase in the current quarter is due primarily to higher net revenue as a result of both increased sales across all customer classes and rate adjustments associated with base rate cases at Entergy Arkansas and Entergy Texas implemented during the current quarter and prior year rate adjustments at Entergy Gulf States Louisiana and Entergy Louisiana under their formula rate plans. Partially offsetting higher net revenue was higher non-fuel operation and maintenance expense driven by increased compensation-related expenses and higher outage costs at generating units. The net effect of lower depreciation expense, lower other income, and higher income tax expense were also partially offsetting. New depreciation rates established in the Arkansas rate case settlement contributed to the reduction in depreciation expense in the current quarter. Other income decreased as a result of the absence of income from storm carrying charges and a gain on a land sale recorded in third quarter 2009. Higher income tax expense was primarily due to the net effect of consolidated income tax adjustments across the Entergy companies, partially offset by state income tax benefits realized in connection with storm cost financings in Louisiana.

Electricity usage, in gigawatt-hour sales by customer segment, is included in Table 4. Current quarter sales reflect the following:

·	Residential sales in third quarter 2010, on a weather-adjusted basis, increased 0.9 percent compared to third quarter 2009.

·	Commercial and governmental sales, on a weather-adjusted basis, increased 1.7 percent quarter over quarter.

·	Industrial sales in the third quarter increased 8.5 percent compared to the same quarter of 2009.

The industrial customer segment reflected strong sales growth on continuing signs of economic recovery, which was also evident in the residential and commercial classes. In addition, residential and commercial sales benefited from significantly warmer-than-normal weather. The improvement in industrial sales in the third quarter 2010 was driven by inventory restocking and strong exports with the chemicals, refining, and miscellaneous manufacturing sectors leading the improvement.

Table 4 provides a comparative summary of the Utility’s operational performance measures.

Table 4: Utility Operational Performance Measures
Third Quarter and Year-to-Date 2010 vs. 2009 (see Appendix D for definitions of measures)

	Third Quarter				Year-to-Date
	2010	2009	% Change	% Weather Adjusted	2010	2009	% Change	% Weather Adjusted
GWh billed
Residential	12,365	11,213	10.3%	0.9%	29,715	26,206	13.4%	2.2%
Commercial and governmental	9,341	8,794	6.2%	1.7%	23,789	22,644	5.1%	2.1%
Industrial	10,276	9,473	8.5%	8.5%	28,871	26,402	9.4%	9.4%
Total Retail Sales	31,982	29,480	8.5%	3.6%	82,375	75,252	9.5%	4.7%
Wholesale	1,063	1,164	(8.7)%		3,351	3,864	(13.3)%
Total Sales	33,045	30,644	7.8%		85,726	79,116	8.4%
O&M expense per MWh	$16.41	$15.77	4.1%		$17.54	$18.19	(3.6)%
Number of retail customers
Residential					2,356,216	2,335,387	0.9%
Commercial and governmental					350,808	346,574	1.2%
Industrial					47,622	47,647	(0.1)%

Appendix B provides information on selected pending local and federal regulatory cases.

III.	Entergy Nuclear

Entergy Nuclear earned $0.71 per share on an as-reported basis in third quarter 2010, compared to as-reported earnings of $1.02 per share in third quarter 2009. On an operational basis, third quarter 2010 Entergy Nuclear earnings were $0.85 per share versus $1.07 per share in the third quarter of the prior year. Entergy Nuclear’s operational earnings decreased as a result of lower net revenue due primarily to lower generation resulting from additional planned and unplanned outages. Also, contributing to the decrease in earnings was higher non-fuel operation and maintenance expense due to higher compensation-related expenses. Partially offsetting these decreases was lower income tax expense, which was primarily due to adjustments in an income tax reserve and the net effect of consolidated income tax adjustments.

Table 5 provides a comparative summary of Entergy Nuclear’s operational performance measures.

Table 5: Entergy Nuclear Operational Performance Measures
Third Quarter and Year-to-Date 2010 vs. 2009 (see Appendix D for definitions of measures)

	Third Quarter			Year-to-Date
	2010	2009	% Change	2010	2009	% Change
Net MW in operation	4,998	4,998	–%	4,998	4,998	–%
Average realized price per MWh	$61.41	$61.70	–%	$59.27	$61.68	(4)%
Production cost per MWh (a)	$27.79	$22.57	23%	$25.28	$23.28	9%
Non-fuel O&M expense/purchased power per MWh (a)	$28.77	$22.11	30%	$25.94	$23.18	12%
GWh billed	9,888	10,876	(9)%	30,011	29,929	–%
Capacity factor	91%	100%	(9)%	92%	91%	1%
Refueling outage days:
FitzPatrick (b)	18	–		18	–
Indian Point 2	–	–		33	–
Indian Point 3	–	–		–	36
Palisades	–	–		–	41
Pilgrim	–	–		–	31
Vermont Yankee	–	–		29	–

(a)	Third quarter and year-to-date periods in 2009 and 2010 exclude the effect of the special item for non-utility nuclear spin-off expenses.

(b)	Table reflects the duration of refueling outages that occurred in third quarter 2010; the FitzPatrick refueling outage continued for 17 days into the fourth quarter 2010.

Table 6 provides capacity and generation sold forward projections for Entergy Nuclear.

Table 6: Entergy Nuclear’s Capacity and Generation Projected Sold Forward
Third Quarter 2010 through 2015 (see Appendix D for definitions of measures)
	Balance of 2010	2011	2012	2013	2014	2015
Energy
Planned TWh of generation (c)	10	41	41	40	41	41
Percent of planned generation sold forward (d)
Unit-contingent	57%	78%	50%	25%	14%	12%
Unit-contingent with availability guarantees	33%	17%	14%	6%	3%	3%
Firm LD	–%	3%	14%	–%	8%	–%
Offsetting positions	–%	(3)%	(2)%	–%	–%	–%
Total Energy Sold Forward (net)	90%	95%	76%	31%	25%	15%
Average contract price per MWh (e)	$57	$53	$50	$49	$51	$51
						.
Capacity
Planned net MW in operation (c)	4,998	4,998	4,998	4,998	4,998	4,998
Percent of capacity sold forward
Bundled capacity and energy contracts	27%	26%	18%	16%	16%	16%
Capacity contracts	57%	31%	29%	26%	10%	–%
Total Capacity Sold Forward	84%	57%	47%	42%	26%	16%
Average capacity contract price per kW per month	$2.4	$3.0	$3.0	$2.8	$2.7	$–

Blended Capacity and Energy Recap (based on revenues)
Percent of planned energy and capacity sold forward	93%	95%	77%	33%	26%	14%
Average contract revenue per MWh (e)	$59	$55	$52	$52	$53	$51

(c) Assumes successful license renewal at all plants. License renewal applications are in process for four units (with current license expirations noted parenthetically): Vermont Yankee (3/21/2012), Pilgrim (6/8/2012), Indian Point 2 (9/28/2013), and Indian Point 3 (12/15/2015).

(d) A portion of EN’s total planned generation sold forward through March 2012 is associated with the Vermont Yankee contract, for which pricing may be adjusted.

(e) Average contract prices exclude payments that may be owed under the value sharing agreement with the New York Power Authority.

IV.	Parent & Other

Parent & Other reported earnings of $0.13 per share on an as-reported basis and an operational basis in third quarter 2010 compared to losses of $(0.20) on an as-reported basis and $(0.17) on an operational basis in third quarter 2009. Lower income tax expense on Parent & Other activities was the primary factor driving results for the quarter. The current quarter reflects an adjustment in income tax reserves resulting from a favorable Tax Court ruling. The net effect of consolidated income tax adjustments also contributed.

V.	Other Financial Performance Highlights

Earnings Guidance

Entergy affirmed its earnings guidance ranges of $5.95 to $6.80 per share on an as-reported basis and $6.40 to $7.20 per share on an operational basis. On April 15, 2010, Entergy revised its 2010 as-reported earnings guidance to a range of $5.95 to $6.80 per share from $6.15 to $6.95 per share to reflect the potential charge in connection with the previously announced business unwind of the internal organizations created for Enexus Energy Corporation and EquaGen LLC. This charge will be classified as a special item in 2010, and therefore is excluded from the operational earnings per share guidance range. The total potential charge estimated at $0.40 to $0.45 per share, as of April 2010, includes previously identified special items for spin-off dis-synergies and expenses for outside services provided to pursue the spin-off, for which $0.25 per share had already been reflected in as-reported earnings guidance. Efforts to eliminate spin-off dis-synergies are well under way, with expectations to eliminate these costs during 2010.

Year-over-year changes are shown as point estimates and are applied to 2009 earnings to compute the 2010 guidance midpoint. Drivers for the 2010 operational guidance range are listed separately. Because there is a range of possible outcomes associated with each earnings driver, a range is applied to the calculated guidance midpoints to produce Entergy’s guidance ranges for as-reported and operational earnings. The current 2010 earnings guidance is detailed in Table 7 below.

Table 7: 2010 Earnings Per Share Guidance – As-Reported and Operational
(Per share in U.S. $) – Prepared October 2009; As-Reported Updated April 2010 (f)
Segment	Description of Drivers	2009 Earnings per Share	Expected Change	2010 Guidance Midpoint	2010 Guidance Range

Utility, Parent, & Other (includes Non-Nuclear Wholesale Assets)	2009 Operational Earnings per Share	3.22
	Adjustment to normalize weather		0.01
	Increased net revenue due to sales growth and rate actions		0.65
	Increased non-fuel operation and maintenance expense		(0.05)
	Increased depreciation expense		(0.08)
	Decreased other income		(0.15)
	Increased interest expense		(0.05)
	Non-nuclear wholesale assets contribution		(0.20)
	Accretion / other		0.20
	Subtotal	3.22	0.33	3.55

Entergy Nuclear	2009 Operational Earnings per Share	3.45
	Decreased net revenue due to lower pricing and volume		(0.15)
	Increased non-fuel operation and maintenance expense		(0.20)
	Increased depreciation expense		(0.05)
	Increased other income		0.20
	Accretion / other		-
	Subtotal	3.45	(0.20)	3.25

Consolidated Operational	2010 Operational Earnings per Share	6.67	0.13	6.80	6.40 – 7.20

Consolidated As-Reported	2009 As-Reported Earnings per Share
	Changes detailed above		0.13
	2010 Entergy Nuclear spin-off dis-synergies		(0.25)
	2009 Entergy Nuclear spin-off dis-synergies		0.23
	2009 Non-utility nuclear spin-off expenses for outside services at Parent & Other		0.14
	2010 As-Reported Earnings per Share Guidance Range	6.30	0.25	6.55	6.15 – 6.95
	Incremental special items related to the spin-off in connection with the business unwind		(0.15) – (0.20)
	Revised 2010 As-Reported Earnings per Share Guidance Range	6.30	0.05 – 0.10	6.35 – 6.40	5.95 – 6.80

(f) Updated in February 2010 to reflect 2009 final results and in April 2010 to reflect the special item for the total potential charge for the business unwind of Enexus Energy Corporation and EquaGen LLC.

Key assumptions supporting 2010 earnings guidance are as follows:

Utility, Parent & Other

·	Normal weather

·	Retail sales growth of around 4.5% on a weather adjusted basis; around 3% on a normalized basis excluding the effects of industrial expansion

·	Increased revenue associated with rate actions, including storm securitization which is offset by increased interest expense as noted below

·	Increased non-fuel operation and maintenance expense resulting from compensation and benefits expense and increased refueling outage amortization, largely offset by lower customer write-offs and the absence of 2009 storm related items

·	Increased depreciation associated with capital spending at the Utility

·	Decreased other income due to lower carrying charges and the absence of the 2009 gain on sale of land at the Utility

·	Increased interest expense associated with increased debt outstanding at the Utility, including storm securitization, partially offset by lower debt outstanding at the Parent

·	Break-even operations targeted for the non-nuclear wholesale assets business

·	Accretion / other is primarily driven by the effect of share repurchases in both 2009 and 2010

Entergy Nuclear

·	40 TWh of total output, reflecting an approximate 92 percent capacity factor, including 30 day refueling outages at Indian Point 2 and Vermont Yankee in Spring 2010 and FitzPatrick and Palisades in Fall 2010

·	88 percent of energy sold under existing contracts; 12 percent sold into the spot market

·	$57/MWh average energy contract price; $56/MWh average unsold energy price based on published market prices at the end of September 2009 (market prices have since declined with 2010 now averaging around the mid-$40s per MWh)

·	Palisades PPA revenue amortization of $46 million in 2010, down from $53 million in 2009

·	Non-fuel operation and maintenance expense, including refueling outage expense and purchased power, around $25/MWh resulting from increased compensation and benefits expense, higher NRC fees and increased refueling outage amortization

·	Increased depreciation associated with capital spending

·	Increased other income due primarily to the absence of 2009 decommissioning trust other than temporary impairments; earnings guidance does not incorporate assumptions for other than temporary impairments as financial market outcomes are outside of Entergy Nuclear’s control and difficult to predict

·	Offsetting effects of accretion / other are primarily driven by the effect of share repurchases in both 2009 and 2010, largely offset by a higher effective income tax rate in 2010

Share Repurchase Program

·	2010 average fully diluted shares outstanding of approximately 187 million (including effects of share repurchases in both 2009 and 2010)

Effective Income Tax Rate

·	2010 assumes an overall effective income tax rate of 36 percent

Revised 2010 As-Reported Earnings Guidance Range (April 2010)

In connection with the business unwind of the internal organizations for Enexus Energy Corporation and EquaGen LLC, the estimated range of a total potential charge of $0.40 to $0.45 per share reflects the write-off of capitalized costs incurred to date and certain other costs in accordance with generally accepted accounting principles. This charge will be reported as a special item. The range for this charge also includes the previously identified special items for spin-off dis-synergies and expenses for outside services provided to pursue the spin-off in 2010.

Earnings guidance for 2010 should be considered in association with earnings sensitivities as shown in Table 8. These sensitivities illustrate the estimated change in operational earnings resulting from changes in various revenue and expense drivers. Traditionally, the most significant variables for earnings drivers are utility sales for Utility, Parent & Other and energy prices for Entergy Nuclear. The broader earnings guidance range for 2010 also takes into consideration the following:

·	A number of regulatory initiatives (rate actions) under way across the Utility jurisdictions

·	Timing flexibility for executing the share repurchase program across the year (guidance assumed execution on a ratable basis)

·	Potential outcomes for projected pension plan discount rate (guidance assumed 6.75%; actual is 6.1– 6.3%)

Estimated annual impacts shown in Table 8 are intended to be indicative rather than precise guidance.

Table 8: 2010 Earnings Sensitivities
(Per share in U.S. $) – Prepared October 2009
Variable	2010 Guidance Assumption	Description of Change	Estimated Annual Impact (g)
Utility, Parent & Other
Sales growth Residential Commercial / Governmental Industrial	Around 4.5% total sales growth on a weather adjusted basis	1% change in Residential MWh sold 1% change in Comm / Govt MWh sold 1% change in Industrial MWh sold	- / + 0.05 - / + 0.04 - / + 0.02
Rate base	Growing rate base	$100 million change in rate base	- / + 0.03
Return on equity	Authorized regulatory ROEs	1% change in allowed ROE	- / + 0.33
Entergy Nuclear
Capacity factor	92% capacity factor	1% change in capacity factor	- / + 0.07
Energy price	12% energy unsold at $56/MWh in 2010	$10/MWh change for unsold energy	- / + 0.15
Non-fuel operation and maintenance expense	$25/MWh non-fuel operation and maintenance expense/purchased power	$1/MWh change	+ / - 0.13
Outage (lost revenue only)	92% capacity factor, including refueling outages for four nuclear units	1,000 MW plant for 10 days at average portfolio energy price of $57/MWh for sold and $56/MWh for unsold volumes in 2010	- 0.04 / n/a

(g) Based on 2009 average fully diluted shares outstanding of approximately 196 million.

VI.	Appendices

Five appendices are presented in this section as follows:

·	Appendix A includes earnings per share variance analysis and details on special items that relate to the current quarter and year-to-date results.

·	Appendix B provides information on selected pending local and federal regulatory cases.

·	Appendix C provides financial metrics for both current and historical periods. In addition, historical financial and operating performance metrics are included for the trailing eight quarters.

·	Appendix D provides definitions of the operational performance measures and GAAP and non-GAAP financial measures that are used in this release.

·	Appendix E provides a reconciliation of GAAP to non-GAAP financial measures used in this release.

A.	Variance Analysis and Special Items

Appendix A-1 and Appendix A-2 provides details of third quarter and year-to-date 2010 vs. 2009 as-reported and operational earnings variance analysis for Utility, Entergy Nuclear, Parent & Other, and Consolidated.

Appendix A-1: As-Reported and Operational Earnings Per Share Variance Analysis
Third Quarter 2010 vs. 2009
(Per share in U.S. $, sorted in consolidated operational column, most to least favorable)
	Utility			Entergy Nuclear			Parent & Other			Consolidated
	As- Reported	Opera- tional		As- Reported	Opera- tional		As- Reported	Opera- tional		As- Reported	Opera- tional
2009 earnings	1.50	1.50		1.02	1.07		(0.20)	(0.17)		2.32	2.40
Income taxes – other	(0.05)	(0.05)	(h)	0.10	0.10	(i)	0.33	0.33	(j)	0.38	0.38
Net revenue	0.46	0.46	(k)	(0.20)	(0.20)	(l)	0.04	0.04		0.30	0.30
Share repurchase effect	0.07	0.07	(m)	0.03	0.03		0.01	0.01		0.11	0.11
Depreciation/ amortization expense	0.06	0.06	(n)	(0.01)	(0.01)		-	-		0.05	0.05
Interest and other charges	-	-		0.04	0.03		0.01	0.01		0.05	0.04
Nuclear refueling outage expense	-	-		(0.01)	(0.01)		-	-		(0.01)	(0.01)
Decommissioning expense	-	-		(0.01)	(0.01)		-	-		(0.01)	(0.01)
Taxes other than income taxes	(0.03)	(0.03)		(0.01)	(0.01)		0.01	0.01		(0.03)	(0.03)
Other income (deductions)	(0.05)	(0.05)	(o)	(0.02)	(0.02)		(0.07)	(0.07)	(p)	(0.14)	(0.14)
Other operation & maintenance expense	(0.18)	(0.18)	(q)	(0.22)	(0.12)	(r)	-	(0.03)		(0.40)	(0.33)
2010 earnings	1.78	1.78		0.71	0.85		0.13	0.13		2.62	2.76

Appendix A-2: As-Reported and Operational Earnings Per Share Variance Analysis
Year-to-Date Third Quarter 2010 vs. 2009
(Per share in U.S. $, sorted in consolidated operational column, most to least favorable)
	Utility			Entergy Nuclear			Parent & Other			Consolidated
	As- Reported	Opera- tional		As- Reported	Opera- tional		As- Reported	Opera- tional		As- Reported	Opera- tional
2009 earnings	2.80	2.80		2.34	2.51		(0.48)	(0.39)		4.66	4.92
Net revenue	1.15	1.15	(k)	(0.25)	(0.25)	(l)	0.06	0.06	(s)	0.96	0.96
Other than temporary impairment losses	0.00	0.00		0.23	0.23	(t)	0.00	0.00		0.23	0.23
Share repurchase effect	0.14	0.14	(m)	0.07	0.07	(m)	(0.01)	(0.01)		0.20	0.20
Income taxes – other	-	-		(0.03)	(0.03)		0.26	0.16	(j)	0.23	0.13
Interest and other charges	(0.10)	(0.10)	(u)	(0.02)	0.07	(v)	0.09	0.09	(w)	(0.03)	0.06
Depreciation/ amortization expense	0.05	0.05	(n)	(0.02)	(0.02)		0.00	0.00		0.03	0.03
Decommissioning expense	(0.01)	(0.01)		(0.02)	(0.02)		0.00	0.00		(0.03)	(0.03)
Nuclear refueling outage expense	(0.01)	(0.01)		(0.03)	(0.03)		0.00	0.00		(0.04)	(0.04)
Taxes other than income taxes	(0.05)	(0.05)	(x)	0.00	0.00		0.00	0.00		(0.05)	(0.05)
Other income (deductions)	(0.10)	(0.10)	(o)	0.02	0.02		(0.11)	(0.11)	(p)	(0.19)	(0.19)
Other operation & maintenance expense	(0.19)	(0.19)	(q)	(0.46)	(0.22)	(r)	0.06	(0.03)		(0.59)	(0.44)
2010 earnings	3.68	3.68		1.83	2.33		(0.13)	(0.23)		5.38	5.78

(h)

The decrease in the current quarter is due primarily to the unfavorable effect of consolidated income tax adjustments, partially offset by state income tax benefits realized in connection with storm cost financings in Louisiana.

(i)

The increase in the current quarter is due primarily to the favorable effect of consolidated income tax adjustments and the reversal of a tax reserve related to a restructuring of the Entergy Nuclear Power Marketing business.

(j)

The current quarter and year-to-date increases are due primarily to a favorable Tax Court ruling addressing a foreign tax credit computation thus allowing the reversal of a previously established tax reserve on the issue. Also contributing was the favorable effect of consolidated income tax adjustments. Year-to-date is partially offset by decreases in valuation allowances on loss carryovers recorded in the prior year. The as-reported increase reflects tax benefits recorded in connection with the Enexus Energy Corporation and EquaGen LLC business unwind decision resulting from implementation expenses that previously were not deductible for tax purpose.

Utility Net Revenue Variance Analysis 2010 vs. 2009 ($ EPS)
Third Quarter		Year-to-Date
Weather	0.26	Weather	0.55
Sales growth/ pricing	0.24	Sales growth/ pricing	0.47
Other	(0.04)	Other	0.13
Total	0.46	Total	1.15

(k)

The increases in the current quarter and year-to-date periods are due primarily to increased sales volumes across all customer classes, including favorable weather. Also contributing in both periods was pricing adjustments resulting from operating company rate actions in Arkansas, Texas, and Louisiana, with Mississippi also benefiting on a year-to-date basis. Rate refunds recorded at Entergy Louisiana and Entergy Gulf States Louisiana in the third quarter of 2009 also contributed to the current quarter and year-to-date increase. In addition, the year-to-date variance reflects the absence of a regulatory charge at Entergy Texas associated with a May 2009 Federal Energy Regulatory Commission Order.

(l)

The decrease in the current quarter is due primarily to lower generation resulting from an increase in planned and unplanned outage days. On a year-to-date basis, the decrease is primarily due to lower pricing offset somewhat by slightly higher production due to more refueling outages in 2009 through the first three quarters compared to the current year.

(m)	The increases in the current quarter and year-to-date periods represent accretion associated with Entergy’s share repurchase programs.

(n)	The current quarter and year-to-date increases are due primarily to lower depreciation being recorded at Entergy Arkansas in accordance with a rate settlement approved by the Arkansas Public Service Commission.

(o)

The current quarter and year-to-date decreases are due primarily to lower storm-related carrying charges and the absence of a prior year gain recorded on a land sale, partially offset by an increase in affiliate dividend income with Parent & Other arising out of the use of proceeds from storm cost financings in Louisiana.

(p)	The decreases in the current quarter and year-to-date are due primarily to eliminations of higher affiliated dividend at the Utility as described in (o).

(q)	The current quarter and year-to-date decreases are due primarily to higher compensation-related expenses and higher outage costs at generating units.

(r)

The current quarter and year-to-date decreases are due primarily to higher compensation-related expenses and a write-off of capitalized engineering costs associated with a potential uprate project. Also, incremental costs associated with the remediation of the tritium leak at Vermont Yankee were reflected in the year-to-date period. In addition, as-reported results for the current quarter and year-to-date reflects non-utility nuclear spin-off expenses, including the business unwind of Enexus and EquaGen.

(s)	The year-to-date increase is due primarily to higher market heat rates for non-nuclear wholesale assets.

(t)	The increase year-to-date is due to the absence of significant impairments recorded in the prior year associated with decommissioning trust fund investments.

(u)	The year-to-date decrease is due to higher interest expense on increased debt borrowings.

(v)

As-reported interest expense drivers include a first quarter 2010 charge for the balance of fees associated with cancellation of the Enexus credit facility. Going forward, no additional fees will be incurred, resulting in lower interest expense in the second and third quarters of 2010. In addition, the year-to-date change on both as-reported and operational bases reflects lower affiliate guarantee fee expenses with Parent & Other.

(w)	The year-to-date increase is due to lower average revolver rate and lower Parent borrowings including Parent debt redemptions.

(x)	The decrease year-to-date is due primarily to higher ad valorem taxes and higher franchise taxes.

Appendix A-3 lists special items by business with quarter-to-quarter and year-to-date comparisons. Amounts are shown on both earnings per share and net income bases. Special items are those events that are less routine, are related to prior periods, or are related to discontinued businesses. Special items are included in as-reported earnings per share consistent with generally accepted accounting principles (GAAP), but are excluded from operational earnings per share. As a result, operational earnings per share is considered a non-GAAP measure.

Appendix A-3: Special Items (shown as positive / (negative) impact on earnings)
Third Quarter and Year-to-Date 2010 vs. 2009
(Per share in U.S. $)
	Third Quarter			Year-to-Date
	2010	2009	Change	2010	2009	Change
Utility
None	-	-	-	-	-	-

Entergy Nuclear
Non-utility nuclear spin-off expenses (y)	(0.14)	(0.05)	(0.09)	(0.50)	(0.17)	(0.33)

Parent & Other
Non-utility nuclear spin-off expenses (y)	-	(0.03)	0.03	0.10	(0.09)	0.19
Total Special Items	(0.14)	(0.08)	(0.06)	(0.40)	(0.26)	(0.14)

(U.S. $ in millions)
	Third Quarter			Year-to-Date
	2010	2009	Change	2010	2009	Change
Utility
None	-	-	-	-	-	-

Entergy Nuclear
Non-utility nuclear spin-off expenses (y)	(25.2)	(10.3)	(14.9)	(94.0)	(32.0)	(62.0)

Parent & Other
Non-utility nuclear spin-off expenses (y)	-	(5.2)	5.2	18.5	(17.9)	36.4
Total Special Items	(25.2)	(15.5)	(9.7)	(75.5)	(49.9)	(25.6)

(y) Includes non-utility nuclear spin-off dis-synergies and expenses for outside services to pursue the previously planned spin-off in both years and the charge in connection with the business unwind of Enexus Energy Corporation and EquaGen LLC in 2010.

B.	Regulatory Summary

Appendix B provides a summary of selected regulatory cases and events that are pending.

Appendix B: Regulatory Summary Table
Company	Pending Cases / Events
Retail Regulation

Entergy Arkansas Authorized ROE: 10.2% Last Filed Rate Base: $4.0 billion Filed 6/10 based on 6/30/09 test year, with known and measurable changes through 6/30/10	Rate Case Recent Activity: In the first billing cycle of July 2010, EAI implemented its $63.7 million rate increase pursuant to the settlement approved by the APSC in June. Background: In June 2010, the APSC approved a settlement and subsequent compliance tariffs effective for bills rendered for the first billing cycle of July 2010. Key elements of the settlement include a $63.7 million rate increase (after removing $10.1 million for the securitization of ice storm costs) and a 10.2% allowed return on equity.
	Storm Cost Recovery Recent Activity: In August 2010, Entergy Arkansas Restoration Funding, LLC, a special purpose bankruptcy-remote limited liability company wholly-owned by EAI, issued $124.1 million of storm recovery bonds in a single tranche, with an average life of 5.44 years and a coupon of 2.30%. EAI added the proceeds (net of external issuance costs) to its general funds as reimbursement for previous storm-related expenditures. Background: EAI incurred approximately $123 million in estimated restoration costs resulting from the severe ice storm that struck in January 2009. Considering the magnitude of the statewide storm damages, the Arkansas legislature passed legislation authorizing storm reserve accounting in March 2009, followed by the enactment of storm securitization legislation in April. Both pieces of legislation are effective for storms occurring on or after January 1, 2009. The Administrative Law Judge (ALJ) approved the establishment of EAI’s storm cost reserve account on April 16, 2010 using the annual amount of $14.449 million previously established. As part of EAI’s September 4, 2009 rate case filing, EAI included the 2009 ice storm restoration costs in cost-of-service, indicating the ice storm restoration costs would be removed from the pending rate case if the APSC approved EAI’s request to securitize the ice storm costs. Since EAI’s analysis demonstrated that retail customers will benefit from lower costs using securitization versus conventional utility financing, EAI removed ice storm recovery from the pending rate case filing in its rebuttal testimony filed on March 24, 2010. In June 2010, the APSC approved EAI’s financing order. The financing order authorized the issuance of storm recovery bonds in an aggregate amount of $126.3 million, consisting of $121.7 million in storm recovery costs (including $11.5 million of carrying costs assuming a September 23, 2010 bond issuance) and upfront financing costs of $4.6 million. The APSC set a cap of 4.4% on the coupon rate of the securitization bonds to ensure customer savings.
	Show Cause Order Regarding System Agreement / Future Operation and Control of EAI’s Transmission Assets Recent Activity: EAI continued to file testimony and participate in the hearing process in the APSC Show Cause proceeding. On August 31, 2010, the APSC directed EAI and all parties to compare all five strategic options at the same time, pursuant to a procedural schedule, as follows: (1) EAI Self-Provide; (2) EAI w/ 3rd party coordination agreements; (3) Successor Arrangements; (4) EAI as a stand-alone member of Southwest Power Pool Regional Transmission Organization (SPP RTO); and (5) EAI as a stand-alone member of Midwest Independent Transmission System Operator (MISO). The procedural schedule calls for EAI to file its assessment and recommendations regarding each strategic option in April 2011, an evidentiary hearing in August 2011 and an APSC order in October 2011. On September 16, 2010, EAI filed an initial draft of the Successor Arrangements. The Successor Arrangements take the form of a draft Commitment, Operations and Dispatch Agreement (CODA). EAI conducted a technical conference to discuss the Successor Arrangement strategic option on September 23, 2010. On September 29, 2010, EAI filed a petition for clarification of the procedural schedule order concerning several issues including the timetable for selecting the most beneficial option for customers. On September 30, 2010, Charles River Associates (CRA) presented its cost-benefit analysis (CBA) of the Entergy and Cleco regions joining the SPP RTO to the Entergy Regional State Committee (E-RSC). CRA is also conducting addendum studies on EAI as a stand-alone member of the SPP RTO and MISO. The SPP RTO stand-alone study is due October 27, 2010, to be followed by the MISO stand-alone study. Background: On February 11, 2010, the APSC issued a Show Cause order opening an inquiry to conduct an investigation, with the intent to render its decision by the end of 2010, regarding the prudence of EAI’s entering a successor pooling agreement with the other Entergy Operating Companies, as opposed to becoming a stand-alone entity upon exit from the System Agreement in December 2013, and whether EAI, as a stand-alone utility should join the SPP RTO. As a parallel matter, the APSC will also monitor whether Entergy will make any meaningful enhancements to its Independent Coordinator of Transmission (ICT) arrangement in 2010 with filings at FERC. EAI noted in its testimony that it is not reasonable to complete a comprehensive evaluation of strategic options by the end of 2010 and that forcing a decision would place parties in the untenable position of making critical decisions based on insufficient information. EAI’s plan is expected to lead to a decision regarding critical path issues in late 2011, however, EAI anticipates several transition plan elements will move forward in 2010 and require ongoing dialogue. In an attempt to reach understanding of complex issues, EAI proposes to hold a series of technical conferences in the coming months targeting specific subject matter. On May 11, 2010, SPP filed a detailed EAI Stand-Alone CBA project schedule, contingent on certain milestones being reached in the SPP Entergy CBA.

Appendix B: Regulatory Summary Table (continued)
Company	Pending Cases / Events
Retail Regulation

Entergy Gulf States Louisiana Authorized ROE Range: 9.9% - 11.4% (electric) 10.0% - 11.0% (gas) Last Filed Rate Base: $2.3 billion (electric) Filed 8/10 based on 12/31/09 test year $0.05 billion (gas) Filed 4/10 based on 9/30/09 test year	Formula Rate Plan Recent Activity: On August 26, 2010, EGSL made its revised 2009 test year FRP filing. The filing reflected a 10.12% earned ROE which is within the bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the FRP sharing mechanism: (1) an extraordinary cost change associated with decommissioning accruals related to EGSL’s River Bend Station approved by the Commission in July, and (2) $25.2 million for capacity costs. The filing was not contested by the Staff or intervenors, and the rates became effective, beginning with the first billing cycle of September 2010, subject to review and final approval by the LPSC. Background: At its October 2009 Business and Executive (B&E) session, the LPSC approved an uncontested settlement resolving the 2007 test year FRP filing and extending the FRP regulatory process for an additional three years. The new FRP was adopted for the 2008-2010 test years and retains the 10.65% ROE midpoint with a +/- 75 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions. Earnings outside the bandwidth are allocated prospectively, 60% to customers and 40% to the company. As part of the settlement, EGSL implemented a one-time rate reset to achieve its 10.65% midpoint ROE for the 2008 test year filing, which was filed October 21, 2009. This filing reflected an 8.64% earned ROE and total rate increase of $44.3 million, including a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification. New rates took effect coincident with the November billing cycle and were subject to review and final approval by the LPSC. All parties also committed to work together to attempt to develop a transmission rider for EGSL. Finally, the settlement included a $3.7 million refund commencing with the November billing cycle for the 2007 test year FRP filing. In January, EGSL implemented a further $23.9 million rate increase pursuant to the special rate implementation filing made in December, primarily for incremental capacity costs approved by the LPSC. At its May 19, 2010 B&E session, the LPSC accepted the joint LPSC Staff / EGSL report reflecting resolution of the 2008 test year FRP filing. The report calls for a prospective reduction in EGSL’s rates of $847 thousand beginning with the June billing cycle and a refund of $494 thousand plus judicial interest through the fuel adjustment clause. On May 28, 2010, EGSL made its 2009 test year FRP filing. The filing reflected a 10.25% earned ROE which is within the bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the FRP sharing mechanism: (1) $9.7 million to reflect an extraordinary cost change associated with a required increase in decommissioning accruals related to EGSL’s River Bend Station consistent with an earlier December 2009 filing, and (2) $20.8 million for capacity costs. Further, in response to a depreciation rate complaint filed at FERC by the LPSC, EGSL presented two ancillary FRP filing proposals based on a new depreciation study that increased depreciation rates and related FRP revenues by either $45.3 million (assuming a 40 year River Bend life) or $24.4 million (60 year life). EGSL also noted that LPSC Staff, EGSL and intervenors continue working to design a transmission rider for EGSL. At its July 2010 B&E session, the LPSC granted EGSL a $7.8 million increase effective September 2010 to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend in response to the NRC notification of a projected shortfall of decommissioning funding assurance. Prior to that, EGSL had no funding in retail rates for decommissioning

Entergy Louisiana Authorized ROE Range: 9.45% - 11.05% Last Filed Rate Base: $3.0 billion Filed 8/10 based on 12/31/09 test year	Formula Rate Plan Recent Activity: On August 26, 2010, ELL made its revised 2009 test year FRP filing. The filing reflected a 10.82% earned ROE which is within the bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the FRP sharing mechanism: (1) an extraordinary cost change associated with decommissioning accruals related to ELL’s Waterford 3 Steam Electric Station approved by the Commission in July, and (2) $2.2 million for capacity costs. The filing was not contested by the Staff or intervenors, and the rates became effective beginning with the first billing cycle of September 2010, subject to review and final approval by the LPSC. Background: At its October 2009 B&E session, the LPSC approved an uncontested settlement resolving the 2006 and 2007 test year FRP filings and extending the FRP regulatory process for an additional three years. The new FRP was adopted for the 2008-2010 test years and retains the 10.25% ROE midpoint with a +/- 80 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions. Earnings outside the bandwidth are allocated prospectively, 60% to customers and 40% to the company. As part of the settlement, ELL implemented the one-time rate reset to achieve its 10.25% midpoint ROE for the 2008 test year filing, which was filed October 21, 2009. This filing reflected a 9.35% earned ROE and total rate increase of $2.5 million, including a $16.3 million cost of service adjustment, less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification. New rates took effect coincident with the November billing cycle and were subject to review and final approval by the LPSC. All parties also committed to work together to attempt to develop a transmission rider for ELL. Finally, the settlement included a $12.9 million refund commencing with the November billing cycle for the 2006 and 2007 test year FRP filings. At its April 21, 2010 B&E session, the LPSC accepted the joint LPSC Staff / ELL report reflecting resolution of the FRP for the 2008 test year. The report called for a prospective reduction in ELL’s rates of $144.4 thousand beginning with the May billing cycle and to refund $72.2 thousand plus judicial interest through the fuel adjustment clause. Further, ELL will move the recovery of approximately $12.5 million of capacity costs associated with EAI’s Wholesale Baseload Capacity Resource from fuel adjustment clause recovery to base rate recovery. On May 14, 2010, ELL made its 2009 test year FRP filing. The filing reflected a 10.82% earned ROE which is within the bandwidth resulting in no cost of service adjustment. The filing also reflected two adjustments outside of the FRP sharing mechanism: (1) a decrease of $7.4 million to reflect reduced capacity costs, and (2) an increase to reflect an extraordinary cost change associated with a required increase in decommissioning accruals related to ELL’s Waterford 3 Steam Electric Station consistent with an earlier December 2009 filing. Further, in response to a depreciation rate complaint filed at FERC by the LPSC, ELL presented two ancillary FRP filing proposals based on a new depreciation study that increased depreciation rates and related FRP revenues by either $96.4 million (assuming a 40 year Waterford 3 life) or $40.5 million (60 year life). ELL also noted that LPSC Staff, ELL and intervenors continue working to design a transmission rider for ELL. At its July 2010 B&E session, the LPSC granted ELL a $3.482 million increase in retail rates effective September 2010 to provide supplemental funding for the decommissioning trust maintained for the for the LPSC-jurisdictional portion of Waterford 3, in response to the NRC notification of a projected shortfall of decommissioning funding assurance. Prior to that, ELL had $2.3 million in retail rates for decommissioning.

Appendix B: Regulatory Summary Table (continued)
Company	Pending Cases/Events
Retail Regulation

Entergy Louisiana (continued)	Acadia Unit 2 Acquisition Recent Activity: During September 2010, Staff and ELL / EGSL began discussions regarding a possible settlement in this matter. ELL / EGSL requested that pre-hearing deadlines be extended to accommodate settlement discussions. As part of their request, ELL / EGSL did not request any change in the current hearing dates of December 9-10 and 13, 2010. All parties represented that they had no objection to the requested extension and on October 19, 2010, the LPSC modified the procedural schedule to extend the pre-hearing dates. On September 30, 2010, the relevant Hart-Scott-Rodino waiting period expired without action. With this clearance, the power purchase agreement (PPA) was replaced by the original tolling agreement effective October 1, 2010. Background: In October 2009, ELL signed a purchase and sale agreement to acquire the 580 MW Unit 2 of the Acadia Energy Center for $300 million ($517/kW). ELL proposes to acquire 100 percent of Acadia Unit 2 and a 50 percent ownership interest in the facility’s common assets. Cleco Power will serve as operator for the entire facility. ELL has committed to sell one third of the output to EGSL in accordance with terms and conditions detailed under the existing System Agreement. The purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from various federal and state regulatory and permitting agencies and the filing of notification under Hart-Scott-Rodino antitrust law. ELL also entered into an interim tolling agreement (ITA) to purchase the capacity and energy output of Acadia Unit 2 expected to commence on May 1, 2010 and to expire at the closing of the acquisition transaction. For the interim period during which federal reviews were pending, ELL entered into an interim PPA with Acadia Power Partners, LLC (APP), which agreement was intended to be replaced by the ITA once federal reviews were completed. ELL initiated its filing at the LPSC on November 13, 2009. Consideration of the application at the January 2011 LPSC B&E Session would accommodate a closing by the March 31, 2011 deadline regarding certain price increases. The Hart-Scott-Rodino Antitrust Improvements Act filing was made in March 2010. On April 9, 2010, the LPSC approved ELL and EGSL’s uncontested request concerning the limited-term ITA, and on July 28, the LPSC approved the PPA. On June 1, 2010, deliveries commenced under the PPA (while regulatory approval was pending). On June 4, 2010, the FERC concluded that the proposed transaction is consistent with the public interest and issued an order authorizing ELL to acquire Acadia Unit 2 from APP. Closing is expected to occur in early 2011.
	Little Gypsy Repowering Recent Activity: During the third quarter 2010, testimony was filed in the Little Gypsy proceeding. The modified procedural schedule calls for hearings to begin in November 2010. There currently is pending before the LPSC an appeal by the LPSC Staff of a decision by the ALJ relating to a dispute between the Staff and industrial intervenors relating to positions regarding the allocation of the project costs among customers. The LPSC is expected to review this appeal at its November 10, 2010 B&E session. In an effort to minimize any delay in the hearings due to this dispute, ELL requested a status conference, which was held on October 19, 2010. At the status conference, the ALJ determined that the hearings would begin on the date currently scheduled and that all issues other than cost allocation would be heard during these hearings. If the LPSC reaches a decision on the appeal at the November 10, 2010 B&E session, a status conference will be held on November 12, 2010, to determine the hearing schedule for the cost allocation issue. The record from the original hearing will be held open until the conclusion of the hearing on cost allocation. Background: On November 8, 2007, the LPSC voted unanimously to approve ELL’s request to repower the 538 MW Little Gypsy unit to utilize CFB technology relying on a dual-fuel approach (petroleum coke and coal), an action that could reduce Louisiana customers’ dependence on natural gas. The approval was subject to a number of conditions, including the development and approval of a construction monitoring plan. The order also included a recovery provision for prudently incurred costs in the event circumstances changed materially. On March 11, 2009, the LPSC issued an order directing ELL to temporarily suspend the Little Gypsy Repowering Project and file a report with the LPSC on the economic viability of the project and develop a recommendation regarding whether to delay the project for an extended time. 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 May 2009, the LPSC unanimously accepted and subsequently issued an order finding that ELL’s recommendation to place the Little Gypsy project in longer-term suspension of 3 years or more was in the public interest and prudent, without prejudice to issues of prudence of timing of decisions, project management, whether ELL may recover project costs from retail customers and the manner of that recovery and whether the project should be cancelled or abandoned as opposed to merely suspended. The quarterly monitoring plan was suspended indefinitely, with ELL instead working cooperatively with the LPSC Staff keeping them informed of activities associated with suspending the project and terminating current contracts related to the project. ELL also dismissed its proceeding to recover cash earnings on Construction Work in Progress (CWIP) for the Little Gypsy project. On October 27, 2009, ELL filed an application and testimony seeking LPSC authorization to cancel the Little Gypsy Unit 3 repowering project allowing ELL to cancel permits, eliminating the requirement to monitor the project for potential restart. This approach requires starting over should the decision be made to engage in a similar future project. In addition, ELL sought to recover cost incurred on a levelized five-year recovery basis to be trued up. In the event ELL’s costs exceed the authorized amount, ELL proposed that it be required to justify any additional recovery. Pursuant to the procedural schedule, in January, ELL filed an updated cost estimate of nearly $215 million, including nearly $193 million of costs incurred through December 31, 2009 and $22 million of net cancellation / project termination costs including AFUDC through March 2011. On June 29, 2010, LPSC Staff and intervenors filed testimony. Among others, LPSC Staff (1) agreed it was prudent to move the project from long-term suspension to cancellation, and the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $819 thousand, costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years and that the LPSC may want to consider 15 years; (4) allowed recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt while acknowledging the LPSC may consider ordering no return; and (5) indicated ELL should be directed to securitize project costs, if legally feasible and in the public interest. HB 1207, creating the Louisiana Electric Investment Recovery Securitization Act, was unanimously passed in the Louisiana legislature and signed by Governor Jindal on July 6, 2010.

Appendix B: Regulatory Summary Table (continued)
Company	Pending Cases/Events
Retail Regulation

Entergy Mississippi Authorized ROE Range: 10.79% - 13.05% (per FRP filing) Last Filed Rate Base: $1.5 billion Filed 3/10 based on 12/31/09 test yr	Formula Rate Plan Recent Activity: None. Background: EMI had been operating under a FRP last approved in December 2002. The FRP allowed the company’s earned ROE to increase or decrease within a bandwidth with no change in rates. Rate changes, if any, were effective on a prospective basis. On March 4, 2010, the MPSC approved modifications to EMI’s FRP that (1) aligned EMI’s FRP more closely with the FRPs of the other regulated gas and electric utilities in Mississippi; (2) provided the opportunity to reset the ROE and bandwidth based upon performance ratings; (3) rescored the performance adjustment factors; (4) eliminated the $14.5 million revenue adjustment limit and changed the 2% of revenues limit to a 4% limit, with any adjustment over 2% requiring a hearing; and (5) directed EMI to phase-out the summer / winter rate differential in residential rates over two years. On March 15, 2010, EMI filed its first evaluation report under its new FRP for the 2009 test year. The filing reflected a 10.66% earned ROE and total rate increase of $11.8 million, including an $8.1 million increase to amortize general plant. The calculated 11.92% FRP midpoint ROE included the benefit of a 0.76% performance incentive. The FRP called for new rates to be implemented in the June billing cycle, subject to review and final approval by the MPSC. On June 25, 2010, the MPSC issued an order approving the terms of a joint stipulation agreement between the Mississippi Public Utilities Staff and EMI for the 2009 test year FRP filing. The agreement calls for no increase but permits EMI to create a regulatory asset for Mississippi Attorney General litigation costs (currently $3.8 million). It also directs EMI to file a depreciation study within the next 12 months.

Entergy New Orleans Authorized ROE Range: 10.7% - 11.5% (electric) 10.25% - 11.25% (gas) Last Filed Rate Base: $0.3 billion (electric) $0.08 billion (gas) Filed 5/10 based on 12/31/09 test yr	Formula Rate Plan Recent Activity: On September 10, 2010, recognizing that ENOI and the City Council of New Orleans’ (CCNO) Advisors were able to reach agreement on some but not all disputed issues, new rates were filed with the CCNO. The new rates reflected an electric rate decrease of $16.504 million and a gas rate increase of $2.287 million effective with the first billing cycle of October 2010. Any additional negotiated rate changes will go before the CCNO for approval prior to implementation. On October 7, 2010, ENOI came to an Agreement in Principle with the CCNO’s Advisors that includes additional black box electric and gas rate changes to reflect a total decrease of $18 million for electric rates and no change to gas rates retroactive to the first billing cycle of October 2010. In addition, ENOI will recognize a $3.0 million regulatory asset to be recovered over 36 months commencing January 1, 2011 outside the gas FRP deadband. The agreement also calls for ENOI to withdraw its application to implement certain corrections to its purchased gas adjustment clause upon final approval of the settlement. The CCNO is expected to consider the settlement at its October 21, 2010 meeting. Background: A new three year FRP beginning with the 2009 test year was adopted in ENOI’s rate case settled in April 2009. Key provisions include an 11.1% electric ROE and a +/- 40 basis point bandwidth and a 10.75% gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint ROE, with rates changing on a prospective basis depending on whether ENOI is over or under-earning. The FRP also includes a recovery mechanism for Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure. The FRP may be extended by the mutual agreement of ENOI and the CCNO. The settlement also implemented energy conservation and demand programs. Effective June 1, 2009, pursuant to its April rate case settlement, ENOI implemented a total electric bill reduction of $35.3 million, including conversion of the $10.6 million voluntary recovery credit to a permanent reduction and complete realignment of Grand Gulf recovery from fuel to base rates, and a $4.95 million gas rate increase. On September 17, 2009, the CCNO approved the Energy Smart Resolution. Energy Smart is the energy efficiency program that was filed pursuant to ENOI’s April 2009 rate case settlement. On May 27, 2010, ENOI filed its FRP for the 2009 test year. The electric filing reflected a 14.46% earned ROE and a rate decrease of $12.9 million. The gas filing reflected a 7.10% earned ROE and a rate increase of $2.4 million.

Entergy Texas Authorized ROE: 10.0% Last Filed Rate Base: $1.6 billion Filed 12/09 based on 6/30/09 adjusted test year	Rate Case Recent Activity: On August 6, 2010, ETI filed a stipulation and settlement agreement with the PUCT. Key elements of the settlement include a $68 million rate increase ($59 million for usage on and after August 15, 2010 and an additional $9 million for bills rendered on and after May 2, 2011, the first billing cycle of the month) and a 10.125% allowed return on equity (up from 10%). The settlement specified that River Bend decommissioning costs will be set at $2.019 million annually. In addition, the settlement stipulated to $464 million of net transmission cost to set the baseline investment and return assumptions necessary to make subsequent filings for recovery under a transmission rider. No formula rate plan (Cost of Service Adjustment) or purchased power recovery riders were adopted. Concurrently, the ALJ issued an interim order approving the implementation of the $59 million rate increase. The settlement did not address the competitive generation service (CGS) tariff proposed by ETI, as required in state legislation initially enacted in 2005 and modified in 2009. On October 4, 2010, the ALJ remanded the unanimous settlement to the PUCT and concurrently issued a Proposal for Decision (PFD) recommending that the CGS tariff be rejected due to the potential for a substantial shift in costs from a limited class of eligible and participating customers to remaining customers thus violating the basic principle of cost-causation. In the PFD, the ALJ recognized that the law is clear that ETI be made whole for program costs and any loss of revenues from participating customers. The PFD and the settlement agreement will be considered at the November 10, 2010 PUCT open meeting. Separately, ETI submitted a petition on September 17, 2010 to the PUCT to initiate a rulemaking for a proposed rule allowing for a purchased power capacity cost rider. In the filing, ETI stated that other non-ERCOT utilities generally support a rule authorizing timely recovery of purchased power capacity costs outside a base rate case. Background: ETI implemented a $46.7 million base rate increase pursuant to its black box rate case settlement effective January 28, 2009, for usage beginning December 19, 2008. ETI is in need of baseload resources, and in 2009 EAI elected to offer its Wholesale Baseload (WBL) capacity to the Entergy system as a three-year cost based deal beginning January 1, 2010. ETI projected that the purchase could save customers in the range of $9.5 to $16.0 million over three years. Given expected savings, on September 18, 2009, ETI had requested a cost recovery mechanism to recover the annual capacity costs of approximately $26 million through a Purchased Power Recovery Factor (PCRF) until such time as the costs were reflected in rates after a general rate case or the transaction expired, whichever occurred first. On December 30, 2009, ETI filed a rate case requesting a $198.7 million increase reflecting an 11.5% ROE based on an adjusted June 30, 2009 test year. The filing included a proposed cost of service adjustment (COSA) rider with a three year term beginning with the 2010 calendar test year. Key provisions included a +/- 15 basis point bandwidth, with earnings outside the bandwidth reset to the bottom or top of the band and rates changing prospectively depending upon whether ETI is over- or under-earning. The annual change in revenue requirement was limited to a percentage change in
Appendix B: Regulatory Summary Table (continued)
Company/ Proceeding	Pending Cases/Events
Retail Regulation

Entergy Texas (continued)	Consumer Price Index for urban areas, and the FRP included a provision for extraordinary events greater than $10 million per year which would be considered separately. The filing also proposed a purchased power recovery rider, a CGS tariff and established test year baseline values to be used in the transmission cost recovery factor rider authorized for use by ETI in the 2009 legislative session. Finally, the rate case 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 Texas retail customers have responsibility, in response to the NRC notification of a projected shortfall of decommissioning funding assurance. On February 18, 2010, the ALJ issued an order approving a unanimous settlement on interim rates and the procedural schedule reached on February 11, 2010 with the parties in the rate case. The settlement called for an interim rate increase of $17.5 million to begin on May 1, 2010 and the withdrawal of the PCRF docket pertaining to the Arkansas WBL capacity. The procedural schedule called for a final order to be issued November 1, 2010 and permanent rates to be effective relating back to service rendered on / after September 13, 2010.
Wholesale Regulation

System Energy Resources, Inc.	Recent Activity: None. Background: 10.94% ROE approved by July 2001 FERC order. Last Calculated Rate Base: $1.2 billion calculated for 9/30/10 monthly cost of service

System Agreement	Recent Activity: The Operating Companies continue to meet with the Commissioners, Staffs and / or advisors of retail regulatory commissions to discuss a proposed framework for Successor Arrangements to the current System Agreement, which is being pursued in parallel with evaluation by the E-RSC of the SPP RTO, MISO, and modified ICT alternatives. An initial draft of the Successor Arrangements, in the form of a draft CODA, was provided to state regulators on September 16, 2010. The intent of the draft arrangements is to allow each participating company to realize the operational benefits of a large, voluntary coordinated bulk power electric system, including energy savings associated with joint commitment and dispatch of a larger system and lower overall reserve margins, while seeking to address key concerns expressed about the historic litigation related to the current agreement. On August 13, 2010, the FERC reaffirmed its prior decision that refunds were appropriate for a limited fifteen-month period (from 1995 to 1996) due to changes in the treatment of interruptible load in the allocation of costs among the Operating Companies under the System Agreement. Requests for rehearing and clarification of the FERC’s August 13, 2010, order are currently pending before the FERC. Resolution of this proceeding is expected to have implications regarding the question of whether FERC provided sufficient rationale for not ordering refunds in the System Agreement case. The Operating Companies revised the 2010 bandwidth filing based on 2009 calendar year production costs on September 21, 2010 reflecting a payment of $41.6 million (up from $27.3 million) from EAI collectively to ELL and EMI. The 2010 bandwidth filing has been set for hearing by the FERC. Background: The System Agreement case addresses the allocation of production costs among the Utility Operating Companies. In 2005, the FERC issued orders that require each Operating Company’s production costs to be within + / - 11% of System average production costs and set 2007 as the first possible year of payments among Entergy’s Operating Companies, based on calendar year 2006 actual production costs. Upon appeal, the DC Circuit remanded to the FERC for reconsideration of the FERC's conclusion it did not have the authority to order refunds and the decision to delay the implementation of the bandwidth remedy. The remand is pending at FERC. Bandwidth filings for production costs required payments from EAI to various other Operating Companies of approximately $252 million, $252 million and $390 million for the 2007, 2008 and 2009 bandwidth filings respectively. FERC set each of these bandwidth filings for hearing following protests from retail regulatory commissions and / or third parties. A final order in the 2007 bandwidth proceeding has been issued by the FERC, and requests for rehearing and clarification have been filed. Bandwidth proceedings based on 2008 and 2009 remain outstanding. On May 25, 2010, the Utility Operating Companies filed testimony refuting the LPSC’s claims in its April 16, 2010 filing at the FERC alleging that Entergy violated the System Agreement by permitting EAI to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility Operating Companies’ customers. The LPSC filing also stated these non-requirements sales caused harm to the Operating Companies’ customers of $144.4 million over the period 2000-2009, and these customers should be compensated for this harm by Entergy’s shareholders. Hearings were held in the third quarter. The parties are in the process of filing their post-hearing briefs. The System Agreement has been and continues to be the subject of ongoing litigation. As a result, EAI and EMI submitted their eight year notices to withdraw from the System Agreement effective December 2013 and November 2015, respectively. On November 19, 2009, FERC accepted notices of cancellation and determined EAI and EMI are permitted to withdraw from the System Agreement following the 96 month notice period without payment of a fee or being required to otherwise compensate the remaining Entergy Operating Companies as a result of withdrawal. FERC stated it expected Entergy and all interested parties to move forward and develop details of all needed successor arrangements and encouraged Entergy to file its Section 205 filing for post-2013 arrangements as soon as possible. The LPSC and CCNO have requested rehearing of the FERC’s decision. EAI continues to evaluate alternatives, including stand-alone operation of its generation facilities, EAI participating as a member of the SPP RTO or MISO, potential Successor Arrangements and third party coordination agreements. In early April 2010, Entergy Corporation and the Entergy Operating Companies determined in connection with their decision-making process that it is appropriate to agree and commit that no Entergy Operating Company will enter voluntarily into successor arrangements with the other Entergy Operating Companies if its retail regulator finds successor arrangements are not in the public interest.

Appendix B: Regulatory Summary Table (continued)
Company/ Proceeding	Pending Cases/Events
Wholesale Regulation

Independent Coordinator of Transmission Authorized ROE: 11.0% (z) Last Filed Rate Base: $2.2 billion (aa) Filed 5/10 based on 12/31/09 test year	Recent Activity: On September 17, 2010, the Operating Companies filed a request for a one year interim extension of the ICT arrangement expiring November 17, 2010. On October 13, 2010, the Utility Operating Companies amended their initial filing to extend the ICT arrangement (with certain modifications) to a maximum of two years from one year. This will help provide sufficient time for analysis and implementation of other alternatives to the current structure. The filing stated that, if approved by the E-RSC during its October 20-21, 2010 meeting, the companies will make a subsequent filing with the FERC to provide the E-RSC authority upon unanimous approval of all E-RSC members to (1) propose modifications to cost allocation methodology for transmission projects and (2) add transmission projects to the Construction Plan. On September 30, 2010, CRA presented its CBA of the Entergy and Cleco regions joining the SPP RTO. The findings of the CBA indicate that the Entergy region (including entities beyond the Operating Companies) would realize anywhere from a net cost of $(438) million to a net benefit of $387 million, primarily depending upon transmission cost allocation issues. Background: In November 2006, the Utility Operating Companies installed SPP as their ICT with an initial term of four years unless Entergy files and the FERC approves an extension beyond that four year period. The Operating Companies did not transfer control of the transmission system but rather vested the ICT with responsibility, among others, for granting or denying transmission service, administering the OASIS node, developing a base plan for the transmission system that is used to determine whether costs of transmission upgrades should be rolled into transmission rates or directly assigned to customers requesting or causing the upgrade to be built, serving as reliability coordinator the transmission system and overseeing the Weekly Procurement Process (WPP). In its November 17, 2009 FERC filing, in anticipation of the expiration of the initial term of the ICT, a process was proposed for the evaluation of modifications to, or the replacement of, the current ICT and WPP arrangements. The process will facilitate review by the FERC, Entergy’s retail regulators, and interested stakeholders of two primary alternatives: 1) the adoption of certain modifications to the current ICT arrangements, or 2) a transition to membership in the SPP RTO. Following the November 17 filing, the Operating Companies also determined it was appropriate to evaluate the MISO as an additional alternative. A critical factor in the Operating Companies’ proposal will be the opinion and recommendation of the E-RSC, formed in the Fall of 2009, which included one representative from each of the Entergy Operating Company retail regulators, to consider several of the issues related to the Entergy transmission system. The Utility Operating Companies expect that the E-RSC will reflect in its evaluation process the cost-benefit analysis underway now by CRA that will compare the current ICT arrangement to joining the SPP RTO and MISO. In addition, the E-RSC is currently considering potential modifications to the ICT arrangement, including, among others, providing the E-RSC with authority (upon a unanimous vote) to (1) require the Entergy Operating Companies to file with the FERC proposed modifications to the cost allocation policy for transmission upgrades and (2) add projects to the Operating Companies’ transmission construction plan. It is anticipated certain potential modifications to the ICT will be implemented in November 2010, with other potential modifications being considered if the ICT is ultimately determined to be the appropriate longer term option. If one of the RTOs is deemed the preferred alternative, it is anticipated that the implementation process may take at least 12-18 months after a decision is made. While alternatives are being explored, Entergy has already taken the voluntary step to more closely align its transmission planning criteria with the anticipated modifications to the NERC planning standards. Entergy believes that the current ICT arrangements have produced benefits, and, if modified as a result of this process, can continue to benefit customers and competition. The SPP RTO and MISO alternatives also have the potential to produce benefits. The progress of cost-benefit analysis will be closely monitored, including its treatment of the costs associated with any socialization of transmission upgrades constructed to integrate wind development.

(z) Applies to sales made under Entergy’s FERC-jurisdictional Open Access Transmission Tariff (OATT).

(aa) Reflects transmission rate base in Entergy’s FERC OATT filing, for which such amounts are also reflected in the rate base figures for each of the Operating Companies shown above.

C.	Financial Performance Measures and Historical Performance Measures

Appendix C-1 provides comparative financial performance measures for the current quarter. Appendix C-2 provides historical financial performance measures and operating performance metrics for the trailing eight quarters. Financial performance measures in both tables include those calculated and presented in accordance with generally accepted accounting principles (GAAP), as well as those that are considered non-GAAP measures.

As-reported measures are computed in accordance with GAAP as they include all components of net income, including special items. Operational measures are non-GAAP measures as they are calculated using operational net income, which excludes the impact of special items. A reconciliation of operational measures to as-reported measures is provided in Appendix E.

Appendix C-1: GAAP and Non-GAAP Financial Performance Measures
Third Quarter 2010 vs. 2009 (see Appendix D for definitions of certain measures)

For 12 months ending September 30	2010	2009	Change
GAAP Measures
Return on average invested capital – as-reported	8.2%	7.1%	1.1%
Return on average common equity – as-reported	15.5%	13.2%	2.3%
Net margin – as-reported	11.7%	9.7%	2.0%
Cash flow interest coverage	8.0	5.5	2.5
Book value per share	$48.10	$44.91	$3.19
End of period shares outstanding (millions)	181.5	188.9	(7.4)

Non-GAAP Measures
Return on average invested capital – operational	8.7%	7.5%	1.2%
Return on average common equity – operational	16.6%	14.1%	2.5%
Net margin – operational	12.5%	10.3%	2.2%

As of September 30 ($ in millions)	2010	2009	Change
GAAP Measures
Cash and cash equivalents	1,931	1,131	800
Revolver capacity	2,216	1,647	569
Total debt	12,247	11,522	725
Securitization debt	940	301	639
Debt to capital ratio	57.5%	56.7%	0.8%
Off-balance sheet liabilities:
Debt of joint ventures – Entergy’s share	108	118	(10)
Leases – Entergy’s share	530	449	81
Total off-balance sheet liabilities	638	567	71

Non-GAAP Measures
Debt to capital ratio, excluding securitization debt	55.6%	56.1%	(0.5)%
Total gross liquidity	4,147	2,778	1,369
Net debt to net capital ratio, excluding securitization debt	50.9%	53.4%	(2.5%)
Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt	52.5%	54.8%	(2.3%)

Appendix C-2: Historical Performance Measures (see Appendix D for definitions of measures)
			4Q08	1Q09	2Q09	3Q09	4Q09	1Q10	2Q10	3Q10	09YTD	10YTD
Financial
		EPS – as-reported ($)	0.89	1.20	1.14	2.32	1.64	1.12	1.65	2.62	4.66	5.38
		Less – special items ($)	(0.10)	(0.09)	(0.09)	(0.08)	(0.11)	(0.21)	(0.06)	(0.14)	(0.26)	(0.40)
		EPS – operational ($)	0.99	1.29	1.23	2.40	1.75	1.33	1.71	2.76	4.92	5.78
	Trailing Twelve Months
		ROIC – as-reported (%)	8.1	7.6	7.5	7.1	7.7	7.6	8.1	8.2	7.1	8.2
		ROIC – operational (%)	8.4	8.0	7.8	7.5	8.1	8.0	8.5	8.7	7.5	8.7
		ROE – as-reported (%)	15.4	14.1	13.7	13.2	14.9	13.8	14.8	15.5	13.2	15.5
		ROE – operational (%)	16.1	15.0	14.6	14.1	15.7	14.9	15.8	16.6	14.1	16.6
		Cash flow interest coverage	6.5	6.5	6.7	5.5	6.1	6.3	6.6	8.0	5.5	8.0
		Debt to capital ratio (%)	59.7	57.4	55.9	56.7	57.4	57.0	56.6	57.5	56.7	57.5
		Debt to capital ratio, excluding securitization debt (%)	59.1	56.7	55.3	56.1	55.6	55.2	54.8	55.6	56.1	55.6
		Net debt to net capital ratio, excluding securitization debt (%)	54.8	52.6	52.2	53.4	51.5	51.3	51.6	50.9	53.4	50.9
Utility
		GWh billed
		Residential	6,992	7,893	7,100	11,213	7,421	9,645	7,705	12,365	26,206	29,715
		Commercial & Gov’t	6,992	6,756	7,095	8,794	7,240	7,064	7,384	9,341	22,644	23,789
		Industrial	8,626	8,139	8,790	9,473	9,235	8,733	9,862	10,276	26,402	28,871
		Wholesale	1,240	1,387	1,313	1,164	998	1,317	971	1,063	3,864	3,351
		O&M expense/MWh	$23.95	$18.51	$20.96	$15.77	$20.18	$17.29	$19.21	$16.41	$18.19	$17.54
		Reliability
		SAIFI	1.9	1.8	1.7	1.7	1.8	1.7	1.8	1.8	1.7	1.8
		SAIDI	216	208	194	203	210	213	207	198	203	198
Entergy Nuclear
		Net MW in operation	4,998	4,998	4,998	4,998	4,998	4,998	4,998	4,998	4,998	4,998
		Avg. realized price per MWh	$56.69	$63.84	$59.22	$61.70	$59.43	$58.72	$57.69	$61.41	$61.68	$59.27
		Production cost/MWh (bb)	$22.77	$23.14	$24.30	$22.57	$23.20	$23.70	$24.40	$27.79	$23.28	$25.28
		Non-fuel O&M expense/ purchased power per MWh (bb)	$23.06	$22.44	$25.33	$22.11	$23.60	$23.63	$25.49	$28.77	$23.18	$25.94
		GWh billed	10,489	10,074	8,980	10,876	11,052	10,255	9,868	9,888	29,929	30,011
		Capacity factor (%)	94	92	81	100	99	94	90	91	91	92

(bb) 2009 and 2010 excludes the effect of the non-utility nuclear spin-off expenses special item at Entergy Nuclear.

D.	Definitions

Appendix D provides definitions of certain operational performance measures, as well as GAAP and non-GAAP financial measures, all of which are referenced in this release.

Appendix D: Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures
Utility
GWh billed	Total number of GWh billed to all retail and wholesale customers
Operation & maintenance expense	Operation, maintenance and refueling expenses per MWh of billed sales, excluding fuel
SAIFI	System average interruption frequency index; average number per customer per year, excluding the impact of major storm activity
SAIDI	System average interruption duration index; average minutes per customer per year, excluding the impact of major storm activity
Number of customers	Number of customers at end of period
Competitive Businesses
Planned TWh of generation	Amount of output expected to be generated by Entergy Nuclear for nuclear units considering plant operating characteristics, outage schedules, and expected market conditions which impact dispatch, assuming timely renewal of plant operating licenses
Percent of planned generation sold forward	Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts or options (consistent with assumptions used in earnings guidance) that may or may not require regulatory approval
Unit-contingent	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
Unit-contingent with availability guarantees	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, unless the actual availability over a specified period of time is below an availability threshold specified in the contract
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, defaulting party must compensate the other party as specified in the contract
Offsetting positions	Transactions for the purchase of energy, generally to offset a Firm LD transaction which was used as a placeholder until a unit contingent transaction could be originated and executed
Planned net MW in operation	Amount of capacity to be available to generate power considering uprates planned to be completed within the calendar year
Bundled energy & capacity contract	A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold
Capacity contract	A contract for the sale of the installed capacity product in regional markets managed by ISO New England and the New York Independent System Operator
Average contract price per MWh or per kW per month	Price at which generation output and / or capacity is expected to be sold to third parties (including offsetting positions), given existing contract or option exercise prices based on expected dispatch or capacity, excluding the revenue associated with the amortization of the below-market Power Purchase Agreement for Palisades
Average contract revenue per MWh	Price at which the combination of generation output and capacity are expected to be sold to third parties (including offsetting positions), given existing contract or option exercise prices based on expected dispatch, excluding the revenue associated with the amortization of the below-market PPA for Palisades
Entergy Nuclear
Net MW in operation	Installed capacity owned and operated by Entergy Nuclear
Average realized price per MWh	As-reported revenue per MWh billed for all non-utility nuclear operations, excluding revenue from the amortization of the Palisades below-market PPA
Production cost per MWh	Fuel and non-fuel operation and maintenance expenses according to accounting standards that directly relate to the production of electricity per MWh
Non-fuel O&M expense/purchased power per MWh	Operation, maintenance and refueling expenses and purchased power per MWh billed, excluding fuel
GWh billed	Total number of GWh billed to all customers
Capacity factor	Normalized percentage of the period that the plants generate power
Refueling outage duration	Number of days lost for scheduled refueling outage during the period

Financial measures defined in the below table include measures prepared in accordance with generally accepted accounting principles, (GAAP), as well as non-GAAP measures. Non-GAAP measures are included in this release in order to provide metrics that remove the effect of less routine financial impacts from commonly used financial metrics.

Appendix D: Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures (continued)
Financial Measures – GAAP
Return on average invested capital – as-reported	12-months rolling net income attributable to Entergy Corporation (Net Income) adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital
Return on average common equity – as-reported	12-months rolling Net Income divided by average common equity
Net margin – as-reported	12-months rolling Net Income divided by 12 months rolling revenue
Cash flow interest coverage	12-months cash flow from operating activities plus 12-months rolling interest paid, divided by interest expense
Book value per share	Common equity divided by end of period shares outstanding
Revolver capacity	Amount of undrawn capacity remaining on corporate and subsidiary revolvers
Total debt	Sum of short-term and long-term debt, notes payable, capital leases, and preferred stock with sinking fund on the balance sheet less non-recourse debt, if any
Debt of joint ventures (Entergy’s share)	Debt issued by business joint ventures at non-nuclear wholesale assets
Leases (Entergy’s share)	Operating leases held by subsidiaries capitalized at implicit interest rate
Debt to capital	Gross debt divided by total capitalization
Securitization debt	Debt associated with securitization bonds issued to recover storm costs from hurricanes Rita, Ike and Gustav at Entergy Texas and the 2009 ice storm at Entergy Arkansas

Financial Measures – Non-GAAP
Operational earnings	As-reported Net Income adjusted to exclude the impact of special items
Return on average invested capital – operational	12-months rolling operational Net Income adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital
Return on average common equity – operational	12-months rolling operational Net Income divided by average common equity
Net margin – operational	12-months rolling operational Net Income divided by 12 months rolling revenue
Total gross liquidity	Sum of cash and revolver capacity
Debt to capital, excluding securitization debt	Gross debt divided by total capitalization, excluding securitization debt
Net debt to net capital, excluding securitization debt	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents, excluding securitization debt
Net debt including off-balance sheet liabilities, excluding securitization debt	Sum of gross debt and off-balance sheet debt less cash and cash equivalents divided by sum of total capitalization and off-balance sheet debt less cash and cash equivalent, excluding securitization debt

E.	GAAP to Non-GAAP Reconciliations

Appendix E-1 and Appendix E-2 provide reconciliations of various non-GAAP financial measures disclosed in this release to their most comparable GAAP measure.

Appendix E-1: Reconciliation of GAAP to Non-GAAP Financial Measures – Return on Equity, Return on Invested Capital and Net Margin Metrics
($ in millions)
	4Q08	1Q09	2Q09	3Q09	4Q09	1Q10	2Q10	3Q10
As-reported Net Income-rolling 12 months (A)	1,221	1,147	1,103	1,088	1,231	1,210	1,298	1,336
Preferred dividends	20	20	20	20	20	20	20	20
Tax effected interest expense	374	366	368	361	351	372	368	358
As-reported Net Income, rolling 12 months including preferred dividends and tax effected interest expense (B)	1,615	1,533	1,491	1,469	1,602	1,602	1,686	1,714

Special items in prior quarters	(35)	(55)	(54)	(54)	(49)	(53)	(76)	(71)

Special items in current quarter
Nuclear spin-off expenses	(20)	(17)	(17)	(15)	(21)	(40)	(10)	(25)
Total special items (C)	(55)	(72)	(71)	(69)	(71)	(94)	(87)	(96)

Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C)	1,670	1,605	1,562	1,538	1,673	1,696	1,773	1,810

Operational earnings, rolling 12 months (A-C)	1,276	1,219	1,174	1,157	1,302	1,304	1,385	1,432

Average invested capital (D)	19,927	20,126	19,995	20,629	20,748	21,149	20,761	20,802

Average common equity (E)	7,915	8,152	8,045	8,230	8,290	8,745	8,769	8,608

Operating revenues (F)	13,094	13,018	12,275	11,248	10,746	10,716	11,058	11,453

ROIC – as-reported % (B/D)	8.1	7.6	7.5	7.1	7.7	7.6	8.1	8.2

ROIC – operational % ((B-C)/D)	8.4	8.0	7.8	7.5	8.1	8.0	8.5	8.7

ROE – as-reported % (A/E)	15.4	14.1	13.7	13.2	14.9	13.8	14.8	15.5

ROE – operational % ((A-C)/E)	16.1	15.0	14.6	14.1	15.7	14.9	15.8	16.6

Net margin – as-reported % (A/F)	9.3	8.8	9.0	9.7	11.5	11.3	11.7	11.7

Net margin – operational % ((A-C)/F)	9.7	9.4	9.6	10.3	12.1	12.2	12.5	12.5

Appendix E-2: Reconciliation of GAAP to Non-GAAP Financial Measures – Credit and Liquidity Metrics
($ in millions)
	4Q08	1Q09	2Q09	3Q09	4Q09	1Q10	2Q10	3Q10
Gross debt (A)	12,279	12,034	11,510	11,522	12,014	12,152	11,853	12,247
Less securitization debt (B)	310	310	301	301	838	838	829	940
Gross debt, excluding securitization debt (C)	11,969	11,724	11,209	11,221	11,176	11,314	11,024	11,307
Less cash and cash equivalents (D)	1,920	1,803	1,281	1,131	1,710	1,657	1,336	1,931
Net debt, excluding securitization debt (E)	10,049	9,921	9,928	10,090	9,466	9,657	9,688	9,376

Total capitalization (F)	20,557	20,975	20,588	20,315	20,939	21,322	20,935	21,290
Less securitization debt (B)	310	310	301	301	838	838	829	940
Total capitalization, excluding securitization debt (G)	20,247	20,665	20,287	20,014	20,101	20,484	20,106	20,350
Less cash and cash equivalents (D)	1,920	1,803	1,281	1,131	1,710	1,657	1,336	1,931
Net capital, excluding securitization debt (H)	18,327	18,862	19,006	18,883	18,391	18,827	18,770	18,419

Debt to capital ratio % (A/F)	59.7	57.4	55.9	56.7	57.4	57.0	56.6	57.5

Debt to capital ratio, excluding securitization debt % (C/G)	59.1	56.7	55.3	56.1	55.6	55.2	54.8	55.6

Net debt to net capital ratio, excluding securitization debt % (E/H)	54.8	52.6	52.2	53.4	51.5	51.3	51.6	50.9

Off-balance sheet liabilities (I)	574	573	569	567	646	644	641	638

Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt % ((E+I)/(H+I))	56.2	54.0	53.6	54.8	53.1	52.9	53.2	52.5

Revolver capacity (J)	645	725	1,585	1,647	1,464	1,417	1,338	2,216

Gross liquidity (D+J)	2,565	2,528	2,866	2,778	3,174	3,074	2,674	4,147

Entergy Corporation’s common stock is listed on the New York and Chicago exchanges under the symbol “ETR”.

Additional investor information can be accessed on-line at

www.entergy.com/investor_relations

*********************************************************************************************************************************

In this news release, and from time to time, Entergy Corporation makes certain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed in: (i) Entergy’s Form 10-K for the year ended December 31, 2009; (ii) Entergy’s Form 10-Qs for the quarters ended March 31, 2010 and June 30, 2010; and (iii) Entergy’s other reports and filings made under the Securities Exchange Act of 1934; (b) uncertainties associated with rate proceedings, formula rate plans and other cost recovery mechanisms; (c) uncertainties associated with efforts to remediate the effects of major storms and recover related restoration costs; (d) nuclear operating and regulatory risks; and (e) legislative and regulatory actions, and conditions in commodity and capital markets during the periods covered by the forward-looking statements, in addition to other factors described elsewhere in this release and in subsequent securities filings.

VII.	Financial Statements

Entergy Corporation

Consolidating Balance Sheet
September 30, 2010
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
ASSETS

CURRENT ASSETS

Cash and cash equivalents:
Cash	$	77,956		$	1,319	$	8,342		$	87,617
Temporary cash investments		977,462			320,752		545,088			1,843,302
Total cash and cash equivalents		1,055,418			322,071		553,430			1,930,919
Securitization recovery trust account		36,280			-		-			36,280
Notes receivable		-			367,662		(367,662	)		-
Accounts receivable:
Customer		590,248			149,964		-			740,212
Allowance for doubtful accounts		(32,793	)		-		(202	)		(32,995	)
Associated companies		19,932			17,293		(37,225	)		-
Other		142,474			-		17,201			159,675
Accrued unbilled revenues		349,950			-		363			350,313
Total accounts receivable		1,069,811			167,257		(19,863	)		1,217,205
Deferred fuel costs		66,071			-		-			66,071
Accumulated deferred income taxes		2,563			340		1,605			4,508
Fuel inventory - at average cost		191,320			-		2,206			193,526
Materials and supplies - at average cost		538,831			311,268		2,093			852,192
Deferred nuclear refueling outage costs		85,483			135,013		-			220,496
System agreement cost equalization		25,976			-		-			25,976
Prepayments and other		80,726			275,225		149,168			505,119
TOTAL		3,152,479			1,578,836		320,977			5,052,292

OTHER PROPERTY AND INVESTMENTS

Investment in affiliates - at equity		1,147,272			1,330,589		(2,439,803	)		38,058
Decommissioning trust funds		1,431,356			1,990,270		-			3,421,626
Non-utility property - at cost (less accumulated depreciation)		160,594			5,554		87,142			253,290
Other		362,974			6,138		35,172			404,284
TOTAL		3,102,196			3,332,551		(2,317,489	)		4,117,258

PROPERTY, PLANT, AND EQUIPMENT

Electric		32,771,834			3,759,384		362,406			36,893,624
Property under capital lease		793,241			-		-			793,241
Natural gas		320,654			-		440			321,094
Construction work in progress		1,165,006			473,872		4,702			1,643,580
Nuclear fuel under capital lease		-			-		-			-
Nuclear fuel		681,200			586,351		-			1,267,551
TOTAL PROPERTY, PLANT AND EQUIPMENT		35,731,935			4,819,607		367,548			40,919,090
Less - accumulated depreciation and amortization		16,543,079			655,181		150,374			17,348,634
PROPERTY, PLANT AND EQUIPMENT - NET		19,188,856			4,164,426		217,174			23,570,456

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:
Regulatory asset for income taxes - net		592,355			-		-			592,355
Other regulatory assets		3,688,785			-		-			3,688,785
Deferred fuel costs		172,202			-		-			172,202
Goodwill		374,099			3,073		-			377,172
Accumulated deferred income taxes		16,338			-		58,365			74,703
Other		215,007			823,987		(4,179	)		1,034,815
TOTAL		5,058,786			827,060		54,186			5,940,032
					-
TOTAL ASSETS	$	30,502,317		$	9,902,873	$	(1,725,152	)	$	38,680,038

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Balance Sheet
September 30, 2010
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES

Currently maturing long-term debt	$	334,291		$	28,492	$	226,000		$	588,783
Notes payable:
Associated companies		-			-		-			-
Other		167,915			-		-			167,915
Account payable:
Associated companies		37,400			6,105		(43,505	)		-
Other		715,661			271,227		22,306			1,009,194
Customer deposits		330,293			-		-			330,293
Taxes accrued		128,851			303,874		(432,725	)		-
Accumulated deferred income taxes		59,402			23,577		3,583			86,562
Interest accrued		176,365			4,371		8,316			189,052
Deferred fuel costs		93,257			-		-			93,257
Obligations under capital leases		3,352			-		-			3,352
Pension and other postretirement liabilities		36,374			5,591		-			41,965
System agreement cost equalization		25,931			-		-			25,931
Other		105,326			274,545		2,840			382,711
TOTAL		2,214,418			917,782		(213,185	)		2,919,015

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued		7,005,512			1,920,897		(780,373	)		8,146,036
Accumulated deferred investment tax credits		296,100			-		-			296,100
Obligations under capital leases		42,873			-		-			42,873
Other regulatory liabilities		555,240			-		-			555,240
Decommissioning and retirement cost liabilities		1,700,383			1,393,140		1,310			3,094,833
Accumulated provisions		381,535			2,403		4,594			388,532
Pension and other postretirement liabilities		1,648,846			462,839		-			2,111,685
Long-term debt		8,522,303			147,697		2,774,513			11,444,513
Other		724,522			275,929		(361,728	)		638,723
TOTAL		20,877,314			4,202,905		1,638,316			26,718,535

Subsidiaries' preferred stock without sinking fund		186,510			-		30,226			216,736

EQUITY

Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2010		2,161,268			774,274		(2,932,994	)		2,548
Paid-in capital		2,416,633			541,945		2,408,513			5,367,091
Retained earnings		2,796,816			3,262,167		2,552,098			8,611,081
Accumulated other comprehensive income (loss)		(124,642	)		203,800		(6,592	)		72,566
Less - treasury stock, at cost (73,229,902 shares in 2010)		120,000			-		5,201,534			5,321,534
Total common shareholders' equity		7,130,075			4,782,186		(3,180,509	)		8,731,752
Subsidiaries' preferred stock without sinking fund		94,000			-		-			94,000
TOTAL		7,224,075			4,782,186		(3,180,509	)		8,825,752

TOTAL LIABILITIES AND EQUITY	$	30,502,317		$	9,902,873	$	(1,725,152	)	$	38,680,038

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Balance Sheet
December 31, 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
ASSETS

CURRENT ASSETS

Cash and cash equivalents:
Cash	$	81,255		$	1,187	$	3,419		$	85,861
Temporary cash investments		1,158,014			392,088		73,588			1,623,690
Total cash and cash equivalents		1,239,269			393,275		77,007			1,709,551
Securitization recovery trust account		13,098			-		-			13,098
Notes receivable		-			1,132,023		(1,132,023	)		-
Accounts receivable:
Customer		331,936			221,756		-			553,692
Allowance for doubtful accounts		(27,428	)		-		(203	)		(27,631	)
Associated companies		27,783			28,940		(56,723	)		-
Other		135,307			-		16,996			152,303
Accrued unbilled revenues		302,293			-		170			302,463
Total accounts receivable		769,891			250,696		(39,760	)		980,827
Deferred fuel costs		126,798			-		-			126,798
Accumulated deferred income taxes		-			-		-			-
Fuel inventory - at average cost		194,826			529		1,500			196,855
Materials and supplies - at average cost		526,543			297,132		2,027			825,702
Deferred nuclear refueling outage costs		106,428			118,862		-			225,290
System agreement cost equalization		70,000			-		-			70,000
Prepayments and other		68,406			432,968		(115,334	)		386,040
TOTAL		3,115,259			2,625,485		(1,206,583	)		4,534,161

OTHER PROPERTY AND INVESTMENTS

Investment in affiliates - at equity		734,578			1,330,589		(2,025,587	)		39,580
Decommissioning trust funds		1,325,863			1,885,320		-			3,211,183
Non-utility property - at cost (less accumulated depreciation)		156,333			6,038		85,293			247,664
Other		77,418			7,730		35,125			120,273
TOTAL		2,294,192			3,229,677		(1,905,169	)		3,618,700

PROPERTY, PLANT, AND EQUIPMENT

Electric		32,426,732			3,540,860		376,180			36,343,772
Property under capital lease		783,096			-		-			783,096
Natural gas		313,817			-		439			314,256
Construction work in progress		1,134,194			411,523		1,602			1,547,319
Nuclear fuel under capital lease		527,521			-		-			527,521
Nuclear fuel		219,317			520,510		-			739,827
TOTAL PROPERTY, PLANT AND EQUIPMENT		35,404,677			4,472,893		378,221			40,255,791
Less - accumulated depreciation and amortization		16,150,763			561,698		153,928			16,866,389
PROPERTY, PLANT AND EQUIPMENT - NET		19,253,914			3,911,195		224,293			23,389,402

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:
Regulatory asset for income taxes - net		619,500			-		-			619,500
Other regulatory assets		3,647,154			-		-			3,647,154
Deferred fuel costs		172,202			-		-			172,202
Goodwill		374,099			3,073		-			377,172
Accumulated deferred income taxes		-			-		-			-
Other		231,156			821,382		(46,232	)		1,006,306
TOTAL		5,044,111			824,455		(46,232	)		5,822,334
					-
TOTAL ASSETS	$	29,707,476		$	10,590,812	$	(2,933,691	)	$	37,364,597

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Balance Sheet
December 31, 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear		Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES

Currently maturing long-term debt	$	406,016		$	30,941	$	275,000		$	711,957
Notes payable:
Associated companies		207,161			-		(207,161	)		-
Other		30,031			-		-			30,031
Account payable:
Associated companies		6,920			7,543		(14,463	)		-
Other		758,886			231,119		8,223			998,228
Customer deposits		323,092			250		-			323,342
Taxes accrued		12,742			-		(12,742	)		-
Accumulated deferred income taxes		41,125			-		7,459			48,584
Interest accrued		187,154			908		4,221			192,283
Deferred fuel costs		219,639			-		-			219,639
Obligations under capital leases		212,496			-		-			212,496
Pension and other postretirement liabilities		49,912			5,119		-			55,031
System agreement cost equalization		187,204			-		-			187,204
Other		48,643			163,328		3,231			215,202
TOTAL		2,691,021			439,208		63,768			3,193,997

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued		6,506,974			3,052,967		(2,137,622	)		7,422,319
Accumulated deferred investment tax credits		308,395			-		-			308,395
Obligations under capital leases		354,233			-		-			354,233
Other regulatory liabilities		421,985			-		-			421,985
Decommissioning and retirement cost liabilities		1,618,844			1,319,450		1,245			2,939,539
Accumulated provisions		127,634			9,090		4,591			141,315
Pension and other postretirement liabilities		1,771,351			469,688		-			2,241,039
Long-term debt		7,897,032			156,556		2,652,150			10,705,738
Other		750,024			317,661		(356,351	)		711,334
TOTAL		19,756,472			5,325,412		164,013			25,245,897

Subsidiaries' preferred stock without sinking fund		186,510			-		30,833			217,343

EQUITY

Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2009		2,161,268			774,274		(2,932,994	)		2,548
Paid-in capital		2,416,633			1,027,164		1,926,245			5,370,042
Retained earnings		2,651,629			2,965,052		2,426,441			8,043,122
Accumulated other comprehensive income (loss)		(130,057	)		59,702		(4,830	)		(75,185	)
Less - treasury stock, at cost (65,634,580 shares in 2009)		120,000			-		4,607,167			4,727,167
Total common shareholders' equity		6,979,473			4,826,192		(3,192,305	)		8,613,360
Subsidiaries' preferred stock without sinking fund		94,000			-		-			94,000
TOTAL		7,073,473			4,826,192		(3,192,305	)		8,707,360

TOTAL LIABILITIES AND EQUITY	$	29,707,476		$	10,590,812	$	(2,933,691	)	$	37,364,597

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Balance Sheet
September 30, 2010 vs December 31, 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
ASSETS

CURRENT ASSETS

Cash and cash equivalents:
Cash	$	(3,299	)	$	132		$	4,923		$	1,756
Temporary cash investments		(180,552	)		(71,336	)		471,500			219,612
Total cash and cash equivalents		(183,851	)		(71,204	)		476,423			221,368
Securitization recovery trust account		23,182			-			-			23,182
Notes receivable		-			(764,361	)		764,361			-
Accounts receivable:
Customer		258,312			(71,792	)		-			186,520
Allowance for doubtful accounts		(5,365	)		-			1			(5,364	)
Associated companies		(7,851	)		(11,647	)		19,498			-
Other		7,167			-			205			7,372
Accrued unbilled revenues		47,657			-			193			47,850
Total accounts receivable		299,920			(83,439	)		19,897			236,378
Deferred fuel costs		(60,727	)		-			-			(60,727	)
Accumulated deferred income taxes		2,563			340			1,605			4,508
Fuel inventory - at average cost		(3,506	)		(529	)		706			(3,329	)
Materials and supplies - at average cost		12,288			14,136			66			26,490
Deferred nuclear refueling outage costs		(20,945	)		16,151			-			(4,794	)
System agreement cost equalization		(44,024	)		-			-			(44,024	)
Prepayments and other		12,320			(157,743	)		264,502			119,079
TOTAL		37,220			(1,046,649	)		1,527,560			518,131

OTHER PROPERTY AND INVESTMENTS

Investment in affiliates - at equity		412,694			-			(414,216	)		(1,522	)
Decommissioning trust funds		105,493			104,950			-			210,443
Non-utility property - at cost (less accumulated depreciation)		4,261			(484	)		1,849			5,626
Other		285,556			(1,592	)		47			284,011
TOTAL		808,004			102,874			(412,320	)		498,558

PROPERTY, PLANT, AND EQUIPMENT

Electric		345,102			218,524			(13,774	)		549,852
Property under capital lease		10,145			-			-			10,145
Natural gas		6,837			-			1			6,838
Construction work in progress		30,812			62,349			3,100			96,261
Nuclear fuel under capital lease		(527,521	)		-			-			(527,521	)
Nuclear fuel		461,883			65,841			-			527,724
TOTAL PROPERTY, PLANT AND EQUIPMENT		327,258			346,714			(10,673	)		663,299
Less - accumulated depreciation and amortization		392,316			93,483			(3,554	)		482,245
PROPERTY, PLANT AND EQUIPMENT - NET		(65,058	)		253,231			(7,119	)		181,054

DEFERRED DEBITS AND OTHER ASSETS

Regulatory assets:
Regulatory asset for income taxes - net		(27,145	)		-			-			(27,145	)
Other regulatory assets		41,631			-			-			41,631
Deferred fuel costs		-			-			-			-
Goodwill		-			-			-			-
Accumulated deferred income taxes		16,338			-			58,365			74,703
Other		(16,149	)		2,605			42,053			28,509
TOTAL		14,675			2,605			100,418			117,698

TOTAL ASSETS	$	794,841		$	(687,939	)	$	1,208,539		$	1,315,441

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Balance Sheet
September 30, 2010 vs December 31, 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES

Currently maturing long-term debt	$	(71,725	)	$	(2,449	)	$	(49,000	)	$	(123,174	)
Notes payable:
Associated companies		(207,161	)		-			207,161			-
Other		137,884			-			-			137,884
Account payable:
Associated companies		30,480			(1,438	)		(29,042	)		-
Other		(43,225	)		40,108			14,083			10,966
Customer deposits		7,201			(250	)		-			6,951
Taxes accrued		116,109			303,874			(419,983	)		-
Accumulated deferred income taxes		18,277			23,577			(3,876	)		37,978
Interest accrued		(10,789	)		3,463			4,095			(3,231	)
Deferred fuel costs		(126,382	)		-			-			(126,382	)
Obligations under capital leases		(209,144	)		-			-			(209,144	)
Pension and other postretirement liabilities		(13,538	)		472			-			(13,066	)
System agreement cost equalization		(161,273	)		-			-			(161,273	)
Other		56,683			111,217			(391	)		167,509
TOTAL		(476,603	)		478,574			(276,953	)		(274,982	)

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued		498,538			(1,132,070	)		1,357,249			723,717
Accumulated deferred investment tax credits		(12,295	)		-			-			(12,295	)
Obligations under capital leases		(311,360	)		-			-			(311,360	)
Other regulatory liabilities		133,255			-			-			133,255
Decommissioning and retirement cost liabilities		81,539			73,690			65			155,294
Accumulated provisions		253,901			(6,687	)		3			247,217
Pension and other postretirement liabilities		(122,505	)		(6,849	)		-			(129,354	)
Long-term debt		625,271			(8,859	)		122,363			738,775
Other		(25,502	)		(41,732	)		(5,377	)		(72,611	)
TOTAL		1,120,842			(1,122,507	)		1,474,303			1,472,638

Subsidiaries' preferred stock without sinking fund		-			-			(607	)		(607	)

EQUITY

Common Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,752,788 shares in 2010 and in 2009		-			-			-			-
Paid-in capital		-			(485,219	)		482,268			(2,951	)
Retained earnings		145,187			297,115			125,657			567,959
Accumulated other comprehensive income (loss)		5,415			144,098			(1,762	)		147,751
Less - treasury stock, at cost		-			-			594,367			594,367
Total common shareholders' equity		150,602			(44,006	)		11,796			118,392
Subsidiaries' preferred stock without sinking fund		-			-			-			-
TOTAL		150,602			(44,006	)		11,796			118,392

TOTAL LIABILITIES AND EQUITY	$	794,841		$	(687,939	)	$	1,208,539		$	1,315,441

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Three Months Ended September 30, 2010
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	2,639,464		$	-		$	(711	)	$	2,638,752
Natural gas		27,263			-			-			27,263
Competitive businesses		-			618,811			47,349			666,161
Total		2,666,727			618,811			46,638			3,332,176

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		671,904			56,114			20,846			748,863
Purchased power		474,238			4,457			5,999			484,694
Nuclear refueling outage expenses		26,819			38,066			-			64,885
Other operation and maintenance		515,613			281,984			11,090			808,688
Decommissioning		26,277			27,081			22			53,380
Taxes other than income taxes		112,902			24,468			847			138,217
Depreciation and amortization		221,627			38,781			4,213			264,621
Other regulatory charges (credits) - net		(1,814	)		-			-			(1,814	)
Total		2,047,566			470,951			43,017			2,561,534

OPERATING INCOME		619,161			147,860			3,621			770,642

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		15,064			-			-			15,064
Interest and dividend income		46,364			38,936			(46,388	)		38,911
Other than temporary impairment losses		-			(206	)		-			(206	)
Miscellaneous - net		(7,017	)		(5,991	)		(1,741	)		(14,748	)
Total		54,411			32,739			(48,129	)		39,021

INTEREST AND OTHER CHARGES
Interest on long-term debt		122,909			(2,826	)		5,995			126,078
Other interest - net		5,080			5,433			(516	)		9,997
Allowance for borrowed funds used during construction		(8,949	)		-			-			(8,949	)
Total		119,040			2,607			5,479			127,126

INCOME BEFORE INCOME TAXES		554,532			177,992			(49,987	)		682,537

Income taxes		216,591			44,129			(76,084	)		184,636

CONSOLIDATED NET INCOME		337,941			133,863			26,097			497,901

Preferred dividend requirements of subsidiaries		4,332			-			683			5,015

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	333,609		$	133,863		$	25,414		$	492,886

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	1.79		$	0.72		$	0.14		$	2.65
DILUTED	$	1.78		$	0.71		$	0.13		$	2.62

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											185,962,431
DILUTED											187,777,172

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Three Months Ended September 30, 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	2,196,255		$	-		$	(794	)	$	2,195,461
Natural gas		24,030			-			-			24,030
Competitive businesses		-			684,214			33,390			717,604
Total		2,220,285			684,214			32,596			2,937,095

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		484,173			58,560			16,396			559,129
Purchased power		373,747			4,108			10,453			388,308
Nuclear refueling outage expenses		26,217			35,224			-			61,441
Other operation and maintenance		457,196			211,683			12,697			681,576
Decommissioning		24,837			25,211			21			50,069
Taxes other than income taxes		103,929			22,412			2,510			128,851
Depreciation and amortization		240,844			36,049			3,748			280,641
Other regulatory charges (credits) - net		(13,224	)		-			-			(13,224	)
Total		1,697,719			393,247			45,825			2,136,791

OPERATING INCOME		522,566			290,967			(13,229	)		800,304

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		14,770			-			-			14,770
Interest and dividend income		50,386			43,878			(29,534	)		64,730
Other than temporary impairment losses		-			(457	)		-			(457	)
Miscellaneous - net		11,156			(4,859	)		(558	)		5,739
Total		76,312			38,562			(30,092	)		84,782

INTEREST AND OTHER CHARGES
Interest on long-term debt		116,997			2,281			10,854			130,132
Other interest - net		10,989			12,771			(1,135	)		22,625
Allowance for borrowed funds used during construction		(8,252	)		-			-			(8,252	)
Total		119,734			15,052			9,719			144,505

INCOME BEFORE INCOME TAXES		479,144			314,477			(53,040	)		740,581

Income taxes		180,055			114,045			(13,686	)		280,414

CONSOLIDATED NET INCOME		299,089			200,432			(39,354	)		460,167

Preferred dividend requirements of subsidiaries		4,332			-			666			4,998

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	294,757		$	200,432		$	(40,020	)	$	455,169

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	1.52		$	1.04		$	(0.21	)	$	2.35
DILUTED	$	1.50		$	1.02		$	(0.20	)	$	2.32

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											193,424,904
DILUTED											195,875,241

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Three Months Ended September 30, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	443,209		$	-		$	83		$	443,291
Natural gas		3,233			-			-			3,233
Competitive businesses		-			(65,403	)		13,959			(51,443	)
Total		446,442			(65,403	)		14,042			395,081

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		187,731			(2,446	)		4,450			189,734
Purchased power		100,491			349			(4,454	)		96,386
Nuclear refueling outage expenses		602			2,842			-			3,444
Other operation and maintenance		58,417			70,301			(1,607	)		127,112
Decommissioning		1,440			1,870			1			3,311
Taxes other than income taxes		8,973			2,056			(1,663	)		9,366
Depreciation and amortization		(19,217	)		2,732			465			(16,020	)
Other regulatory charges (credits )- net		11,410			-			-			11,410
Total		349,847			77,704			(2,808	)		424,743

OPERATING INCOME		96,595			(143,107	)		16,850			(29,662	)

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		294			-			-			294
Interest and dividend income		(4,022	)		(4,942	)		(16,854	)		(25,819	)
Other than temporary impairment losses		-			251			-			251
Miscellaneous - net		(18,173	)		(1,132	)		(1,183	)		(20,487	)
Total		(21,901	)		(5,823	)		(18,037	)		(45,761	)

INTEREST AND OTHER CHARGES
Interest on long-term debt		5,912			(5,107	)		(4,859	)		(4,054	)
Other interest - net		(5,909	)		(7,338	)		619			(12,628	)
Allowance for borrowed funds used during construction		(697	)		-			-			(697	)
Total		(694	)		(12,445	)		(4,240	)		(17,379	)

INCOME BEFORE INCOME TAXES		75,388			(136,485	)		3,053			(58,044	)

Income taxes		36,536			(69,916	)		(62,398	)		(95,778	)

CONSOLIDATED NET INCOME		38,852			(66,569	)		65,451			37,734

Preferred dividend requirements of subsidiaries		-			-			17			17

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	38,852		$	(66,569	)	$	65,434		$	37,717

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.27		$	(0.32	)	$	0.35		$	0.30
DILUTED	$	0.28		$	(0.31	)	$	0.33		$	0.30


*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Nine Months Ended September 30, 2010
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	6,862,237		$	-		$	(2,446	)	$	6,859,791
Natural gas		154,426			-			-			154,426
Competitive businesses		-			1,813,438			126,818			1,940,256
Total		7,016,663			1,813,438			124,372			8,954,473

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		1,706,461			165,738			66,878			1,939,077
Purchased power		1,349,379			10,057			16,619			1,376,055
Nuclear refueling outage expenses		81,489			109,906			-			191,395
Other operation and maintenance		1,421,740			763,402			26,240			2,211,382
Decommissioning		77,542			79,816			65			157,423
Taxes other than income taxes		322,956			73,204			4,437			400,597
Depreciation and amortization		665,503			111,811			12,078			789,392
Other regulatory charges (credits) - net		15,555			-			-			15,555
Total		5,640,625			1,313,934			126,317			7,080,876

OPERATING INCOME		1,376,038			499,504			(1,945	)		1,873,597

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		45,990			-			-			45,990
Interest and dividend income		118,901			116,618			(112,395	)		123,124
Other than temporary impairment losses		-			(1,255	)		-			(1,255	)
Miscellaneous - net		(12,019	)		(13,469	)		(6,562	)		(32,050	)
Total		152,872			101,894			(118,957	)		135,809

INTEREST AND OTHER CHARGES
Interest on long-term debt		369,921			34,027			16,366			420,314
Other interest - net		27,570			17,964			(2,394	)		43,140
Allowance for borrowed funds used during construction		(27,274	)		-			-			(27,274	)
Total		370,217			51,991			13,972			436,180

INCOME BEFORE INCOME TAXES		1,158,693			549,407			(134,874	)		1,573,226

Income taxes		447,608			201,818			(113,199	)		536,227

CONSOLIDATED NET INCOME		711,085			347,589			(21,675	)		1,036,999

Preferred dividend requirements of subsidiaries		12,999			-			2,049			15,048

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	698,086		$	347,589		$	(23,724	)	$	1,021,951

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	3.72		$	1.85		$	(0.13	)	$	5.44
DILUTED	$	3.68		$	1.83		$	(0.13	)	$	5.38

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											187,968,582
DILUTED											189,914,439

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Nine Months Ended September 30, 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	6,143,408		$	-		$	(2,585	)	$	6,140,823
Natural gas		126,914			-			-			126,914
Competitive businesses		-			1,885,330			93,929			1,979,259
Total		6,270,322			1,885,330			91,344			8,246,996

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		1,721,163			157,280			49,249			1,927,692
Purchased power		1,002,645			11,763			20,075			1,034,483
Nuclear refueling outage expenses		77,363			101,091			-			178,454
Other operation and maintenance		1,361,683			615,246			44,533			2,021,462
Decommissioning		74,411			73,647			61			148,119
Taxes other than income taxes		307,660			72,282			5,707			385,649
Depreciation and amortization		683,123			104,713			11,347			799,183
Other regulatory charges (credits) - net		(29,371	)		-			-			(29,371	)
Total		5,198,677			1,136,022			130,972			6,465,671

OPERATING INCOME		1,071,645			749,308			(39,628	)		1,781,325

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		47,499			-			-			47,499
Interest and dividend income		141,915			108,935			(80,843	)		170,007
Other than temporary impairment losses		-			(85,396	)		-			(85,396	)
Miscellaneous - net		2,694			(13,066	)		(10,538	)		(20,910	)
Total		192,108			10,473			(91,381	)		111,200

INTEREST AND OTHER CHARGES
Interest on long-term debt		338,674			6,639			37,942			383,255
Other interest - net		26,775			39,537			3,094			69,406
Allowance for borrowed funds used during construction		(26,547	)		-			-			(26,547	)
Total		338,902			46,176			41,036			426,114

INCOME BEFORE INCOME TAXES		924,851			713,605			(172,045	)		1,466,411

Income taxes		358,217			252,081			(76,197	)		534,101

CONSOLIDATED NET INCOME		566,634			461,524			(95,848	)		932,310

Preferred dividend requirements of subsidiaries		12,997			-			1,996			14,993

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	553,637		$	461,524		$	(97,844	)	$	917,317

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	2.85		$	2.38		$	(0.50	)	$	4.73
DILUTED	$	2.80		$	2.34		$	(0.48	)	$	4.66

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											194,044,214
DILUTED											197,382,562

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Nine Months Ended September 30, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	718,829		$	-		$	139		$	718,968
Natural gas		27,512			-			-			27,512
Competitive businesses		-			(71,892	)		32,889			(39,003	)
Total		746,341			(71,892	)		33,028			707,477

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(14,702	)		8,458			17,629			11,385
Purchased power		346,734			(1,706	)		(3,456	)		341,572
Nuclear refueling outage expenses		4,126			8,815			-			12,941
Other operation and maintenance		60,057			148,156			(18,293	)		189,920
Decommissioning		3,131			6,169			4			9,304
Taxes other than income taxes		15,296			922			(1,270	)		14,948
Depreciation and amortization		(17,620	)		7,098			731			(9,791	)
Other regulatory charges (credits )- net		44,926			-			-			44,926
Total		441,948			177,912			(4,655	)		615,205

OPERATING INCOME		304,393			(249,804	)		37,683			92,272

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		(1,509	)		-			-			(1,509	)
Interest and dividend income		(23,014	)		7,683			(31,552	)		(46,883	)
Other than temporary impairment losses		-			84,141			-			84,141
Miscellaneous - net		(14,713	)		(403	)		3,976			(11,140	)
Total		(39,236	)		91,421			(27,576	)		24,609

INTEREST AND OTHER CHARGES
Interest on long-term debt		31,247			27,388			(21,576	)		37,059
Other interest - net		795			(21,573	)		(5,488	)		(26,266	)
Allowance for borrowed funds used during construction		(727	)		-			-			(727	)
Total		31,315			5,815			(27,064	)		10,066

INCOME BEFORE INCOME TAXES		233,842			(164,198	)		37,171			106,815

Income taxes		89,391			(50,263	)		(37,002	)		2,126

CONSOLIDATED NET INCOME		144,451			(113,935	)		74,173			104,689

Preferred dividend requirements of subsidiaries		2			-			53			55

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	144,449		$	(113,935	)	$	74,120		$	104,634

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	0.87		$	(0.53	)	$	0.37		$	0.71
DILUTED	$	0.88		$	(0.51	)	$	0.35		$	0.72


*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Twelve Months Ended September 30, 2010
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	8,601,969		$	-		$	(2,986	)	$	8,598,983
Natural gas		199,725			-			-			199,725
Competitive businesses		-			2,483,362			171,057			2,654,419
Total		8,801,694			2,483,362			168,071			11,453,127

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		2,012,192			224,479			84,545			2,321,216
Purchased power		1,703,152			13,934			19,690			1,736,776
Nuclear refueling outage expenses		109,142			145,108			-			254,250
Other operation and maintenance		1,896,564			997,077			47,089			2,940,730
Decommissioning		102,815			105,467			86			208,368
Taxes other than income taxes		417,795			96,988			4,025			518,808
Depreciation and amortization		908,619			148,546			15,819			1,072,984
Other regulatory charges (credits) - net		23,198			-			-			23,198
Total		7,173,477			1,731,599			171,254			9,076,330

OPERATING INCOME		1,628,217			751,763			(3,183	)		2,376,797

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		58,036			-			-			58,036
Interest and dividend income		157,491			177,541			(145,462	)		189,570
Other than temporary impairment losses		-			(1,752	)		-			(1,752	)
Miscellaneous - net		(18,795	)		(19,765	)		(12,975	)		(51,535	)
Total		196,732			156,024			(158,437	)		194,319

INTEREST AND OTHER CHARGES
Interest on long-term debt		494,735			36,654			26,387			557,776
Other interest - net		32,748			25,045			(1,097	)		56,696
Allowance for borrowed funds used during construction		(33,961	)		-			-			(33,961	)
Total		493,522			61,699			25,290			580,511

INCOME BEFORE INCOME TAXES		1,331,427			846,088			(186,910	)		1,990,605

Income taxes		478,071			329,003			(172,208	)		634,866

CONSOLIDATED NET INCOME		853,356			517,085			(14,702	)		1,355,739

Preferred dividend requirements of subsidiaries		17,331			-			2,682			20,013

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	836,025		$	517,085		$	(17,384	)	$	1,335,726

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	4.44		$	2.75		$	(0.09	)	$	7.10
DILUTED	$	4.39		$	2.72		$	(0.09	)	$	7.02

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											188,227,792
DILUTED											190,257,734

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Twelve Months Ended September 30, 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	8,438,114		$	-		$	(3,582	)	$	8,434,532
Natural gas		183,409			-			-			183,409
Competitive businesses		-			2,499,061			130,861			2,629,922
Total		8,621,523			2,499,061			127,279			11,247,863

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		2,685,910			211,538			70,511			2,967,959
Purchased power		1,355,340			14,811			22,564			1,392,715
Nuclear refueling outage expenses		100,985			134,051			-			235,036
Other operation and maintenance		1,909,287			821,077			75,293			2,805,657
Decommissioning		99,008			98,113			80			197,201
Taxes other than income taxes		404,304			96,384			6,581			507,269
Depreciation and amortization		919,932			138,098			15,395			1,073,425
Other regulatory charges (credits) - net		(69,458	)		-			-			(69,458	)
Total		7,405,308			1,514,072			190,424			9,109,804

OPERATING INCOME		1,216,215			984,989			(63,145	)		2,138,059

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		63,239			-			-			63,239
Interest and dividend income		183,689			141,761			(100,844	)		224,606
Other than temporary impairment losses		-			(99,859	)		-			(99,859	)
Miscellaneous - net		(8,552	)		(12,665	)		(18,664	)		(39,881	)
Total		238,376			29,237			(119,508	)		148,105

INTEREST AND OTHER CHARGES
Interest on long-term debt		449,547			6,590			56,223			512,360
Other interest - net		39,293			50,709			18,897			108,899
Allowance for borrowed funds used during construction		(35,821	)		-			-			(35,821	)
Total		453,019			57,299			75,120			585,438

INCOME BEFORE INCOME TAXES		1,001,572			956,927			(257,773	)		1,700,726

Income taxes		377,442			268,760			(53,358	)		592,844

CONSOLIDATED NET INCOME		624,130			688,167			(204,415	)		1,107,882

Preferred dividend requirements of subsidiaries		17,329			-			2,662			19,991

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	606,801		$	688,167		$	(207,077	)	$	1,087,891

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	3.15		$	3.57		$	(1.08	)	$	5.64
DILUTED	$	3.07		$	3.48		$	(1.00	)	$	5.55

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC											192,868,552
DILUTED											197,717,203

*Totals may not foot due to rounding.

Entergy Corporation

Consolidating Income Statement
Twelve Months Ended September 30, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)

	U.S. Utilities			Entergy Nuclear			Parent & Other			Consolidated

OPERATING REVENUES
Electric	$	163,855		$	-		$	596		$	164,451
Natural gas		16,316			-			-			16,316
Competitive businesses		-			(15,699	)		40,196			24,497
Total		180,171			(15,699	)		40,792			205,264

OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale		(673,718	)		12,941			14,034			(646,743	)
Purchased power		347,812			(877	)		(2,874	)		344,061
Nuclear refueling outage expenses		8,157			11,057			-			19,214
Other operation and maintenance		(12,723	)		176,000			(28,204	)		135,073
Decommissioning		3,807			7,354			6			11,167
Taxes other than income taxes		13,491			604			(2,556	)		11,539
Depreciation and amortization		(11,313	)		10,448			424			(441	)
Other regulatory charges (credits )- net		92,656			-			-			92,656
Total		(231,831	)		217,527			(19,170	)		(33,474	)

OPERATING INCOME		412,002			(233,226	)		59,962			238,738

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		(5,203	)		-			-			(5,203	)
Interest and dividend income		(26,198	)		35,780			(44,618	)		(35,036	)
Other than temporary impairment losses		-			98,107			-			98,107
Miscellaneous - net		(10,243	)		(7,100	)		5,689			(11,654	)
Total		(41,644	)		126,787			(38,929	)		46,214

INTEREST AND OTHER CHARGES
Interest on long-term debt		45,188			30,064			(29,836	)		45,416
Other interest - net		(6,545	)		(25,664	)		(19,994	)		(52,203	)
Allowance for borrowed funds used during construction		1,860			-			-			1,860
Total		40,503			4,400			(49,830	)		(4,927	)

INCOME BEFORE INCOME TAXES		329,855			(110,839	)		70,863			289,879

Income taxes		100,629			60,243			(118,850	)		42,022

CONSOLIDATED NET INCOME		229,226			(171,082	)		189,713			247,857

Preferred dividend requirements of subsidiaries		1			-			20			22

NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$	229,225		$	(171,082	)	$	189,693		$	247,835

EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$	1.29		$	(0.82	)	$	0.99		$	1.46
DILUTED	$	1.32		$	(0.76	)	$	0.91		$	1.47


*Totals may not foot due to rounding.

Entergy Corporation

Consolidated Cash Flow Statement
Three Months Ended September 30, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)

	2010			2009			Variance

OPERATING ACTIVITIES
Consolidated net income	$	497,901		$	460,167		$	37,734
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments		875			550			325
Other regulatory charges (credits) - net		(1,814	)		(13,224	)		11,410
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		427,758			378,910			48,848
Deferred income taxes, investment tax credits, and non-current taxes accrued		181,718			263,347			(81,629	)
Changes in working capital:
Receivables		(65,881	)		12,968			(78,849	)
Fuel inventory		(1,674	)		13,793			(15,467	)
Accounts payable		21,254			(131,409	)		152,663
Taxes accrued		-			41,738			(41,738	)
Interest accrued		17,833			24,867			(7,034	)
Deferred fuel		(63,585	)		(69,951	)		6,366
Other working capital accounts		(366	)		39,421			(39,787	)
Provision for estimated losses and reserves		289,180			8,316			280,864
Changes in other regulatory assets		505,663			123,030			382,633
Changes in pensions and other postretirement liabilities		(68,233	)		(7,753	)		(60,480	)
Other		(43,374	)		(151,788	)		108,414
Net cash flow provided by operating activities		1,697,255			992,982			704,273

INVESTING ACTIVITIES
Construction/capital expenditures		(492,126	)		(410,784	)		(81,342	)
Allowance for equity funds used during construction		15,064			14,770			294
Nuclear fuel purchases		(96,951	)		(142,153	)		45,202
Proceeds from sale/leaseback of nuclear fuel		-			176,496			(176,496	)
Proceeds from sale of assets and businesses		-			30,401			(30,401	)
Insurance proceeds received for property damages		7,894			32,914			(25,020	)
Changes in transition charge account		(654	)		(11,321	)		10,667
Decrease (increase) in other investments		(229,605	)		7,192			(236,797	)
Proceeds from nuclear decommissioning trust fund sales		486,621			451,164			35,457
Investment in nuclear decommissioning trust funds		(512,086	)		(476,859	)		(35,227	)
Net cash flow used in investing activities		(821,843	)		(328,180	)		(493,663	)

FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		1,746,435			(1,807	)		1,748,242
Common stock and treasury stock		37,047			14,524			22,523
Retirement of long-term debt		(1,339,155	)		(61,942	)		(1,277,213	)
Repurchase of common stock		(527,875	)		(613,125	)		85,250
Redemption of preferred stock		-			(1,847	)		1,847
Changes in credit line borrowings - net		(36,055	)		-			(36,055	)
Dividends paid:
Common stock		(154,887	)		(146,019	)		(8,868	)
Preferred stock		(5,015	)		(4,998	)		(17	)
Net cash flow used in financing activities		(279,505	)		(815,214	)		535,709

Effect of exchange rates on cash and cash equivalents		(512	)		285			(797	)

Net increase (decrease) in cash and cash equivalents		595,395			(150,127	)		745,522

Cash and cash equivalents at beginning of period		1,335,524			1,280,907			54,617

Cash and cash equivalents at end of period	$	1,930,919		$	1,130,780		$	800,139

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	117,150		$	121,159		$	(4,009	)
Income taxes	$	6,910		$	22,054		$	(15,144	)

Entergy Corporation

Consolidated Cash Flow Statement
Nine Months Ended September 30, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)

	2010			2009			Variance

OPERATING ACTIVITIES
Consolidated net income	$	1,036,999		$	932,310		$	104,689
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments		360			(1,080	)		1,440
Other regulatory charges (credits) - net		15,555			(29,371	)		44,926
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		1,259,543			1,076,115			183,428
Deferred income taxes, investment tax credits, and non-current taxes accrued		524,359			512,795			11,564
Changes in working capital:
Receivables		(243,326	)		14,856			(258,182	)
Fuel inventory		3,328			9,830			(6,502	)
Accounts payable		44,348			(189,586	)		233,934
Taxes accrued		-			46,931			(46,931	)
Interest accrued		(10,982	)		(12,176	)		1,194
Deferred fuel		(65,655	)		196,111			(261,766	)
Other working capital accounts		(117,086	)		(117,671	)		585
Provision for estimated losses and reserves		258,962			(10,326	)		269,288
Changes in other regulatory assets		482,960			(332,547	)		815,507
Changes in pensions and other postretirement liabilities		(142,420	)		(52,714	)		(89,706	)
Other		118,144			(34,146	)		152,290
Net cash flow provided by operating activities		3,165,089			2,009,331			1,155,758

INVESTING ACTIVITIES
Construction/capital expenditures		(1,410,708	)		(1,342,840	)		(67,868	)
Allowance for equity funds used during construction		45,990			47,499			(1,509	)
Nuclear fuel purchases		(315,780	)		(291,721	)		(24,059	)
Proceeds from sale/leaseback of nuclear fuel		-			197,706			(197,706	)
Proceeds from sale of assets and businesses		9,675			39,054			(29,379	)
Insurance proceeds received for property damages		7,894			32,914			(25,020	)
Changes in transition charge account		(23,182	)		(8,359	)		(14,823	)
NYPA value sharing payment		(72,000	)		(72,000	)		-
Decrease (increase) in other investments		(167,280	)		24,305			(191,585	)
Proceeds from nuclear decommissioning trust fund sales		1,974,008			1,733,370			240,638
Investment in nuclear decommissioning trust funds		(2,043,361	)		(1,807,589	)		(235,772	)
Net cash flow used in investing activities		(1,994,744	)		(1,447,661	)		(547,083	)

FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		2,272,224			781,497			1,490,727
Common stock and treasury stock		45,763			17,215			28,548
Retirement of long-term debt		(2,113,927	)		(1,084,732	)		(1,029,195	)
Repurchase of common stock		(665,624	)		(613,125	)		(52,499	)
Redemption of preferred stock		-			(1,847	)		1,847
Changes in credit line borrowings - net		(18,932	)		-			(18,932	)
Dividends paid:
Common stock		(453,683	)		(435,178	)		(18,505	)
Preferred stock		(15,048	)		(14,993	)		(55	)
Net cash flow used in financing activities		(949,227	)		(1,351,163	)		401,936

Effect of exchange rates on cash and cash equivalents		250			(218	)		468

Net increase (decrease) in cash and cash equivalents		221,368			(789,711	)		1,011,079

Cash and cash equivalents at beginning of period		1,709,551			1,920,491			(210,940	)

Cash and cash equivalents at end of period	$	1,930,919		$	1,130,780		$	800,139

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	426,461		$	442,345		$	(15,884	)
Income taxes	$	32,964		$	18,915		$	14,049

Noncash financing activities:
Long-term debt retired (equity unit notes)		-		$	(500,000	)	$	500,000
Common stock issued in settlement of equity unit purchase contracts		-		$	500,000		$	(500,000	)
Proceeds from long-term debt issued for the purpose
of refunding prior long-term debt	$	150,000			-		$	150,000
Long-term debt refunded with proceeds from
long-term debt issued in prior period	$	(150,000	)		-		$	(150,000	)

Entergy Corporation

Consolidated Cash Flow Statement
Twelve Months Ended September 30, 2010 vs. 2009
(Dollars in thousands)
(Unaudited)

	2010			2009			Variance

OPERATING ACTIVITIES
Consolidated net income	$	1,355,739		$	1,107,882		$	247,857
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments		932			(7,504	)		8,436
Other regulatory charges (credits) - net		23,198			(69,458	)		92,656
Depreciation, amortization, and decommissioning, including nuclear fuel amortization		1,642,289			1,443,682			198,607
Deferred income taxes, investment tax credits, and non-current taxes accrued		876,248			285,039			591,209
Changes in working capital:
Receivables		(141,738	)		358,858			(500,596	)
Fuel inventory		12,789			22,150			(9,361	)
Accounts payable		219,683			(339,476	)		559,159
Taxes accrued		(122,141	)		122,141			(244,282	)
Interest accrued		6,168			(4,676	)		10,844
Deferred fuel		(189,452	)		553,229			(742,681	)
Other working capital accounts		(227,625	)		(101,626	)		(125,999	)
Provision for estimated losses and reserves		257,258			(228,698	)		485,956
Changes in other regulatory assets		400,350			(1,598,383	)		1,998,733
Changes in pensions and other postretirement liabilities		(17,917	)		997,125			(1,015,042	)
Other		(6,865	)		100,560			(107,425	)
Net cash flow provided by operating activities		4,088,916			2,640,845			1,448,071

INVESTING ACTIVITIES
Construction/capital expenditures		(1,999,113	)		(2,099,438	)		100,325
Allowance for equity funds used during construction		58,036			63,239			(5,203	)
Nuclear fuel purchases		(549,533	)		(388,066	)		(161,467	)
Proceeds from sale/leaseback of nuclear fuel		87,291			244,356			(157,065	)
Proceeds from sale of assets and businesses		10,175			39,054			(28,879	)
Insurance proceeds received for property damages		28,740			32,908			(4,168	)
Changes in transition charge account		(15,859	)		1,003			(16,862	)
NYPA value sharing payment		(72,000	)		(72,000	)		-
Decrease (increase) in other investments		(97,431	)		179,449			(276,880	)
Proceeds from nuclear decommissioning trust fund sales		2,811,161			2,156,887			654,274
Investment in nuclear decommissioning trust funds		(2,902,944	)		(2,252,482	)		(650,462	)
Net cash flow used in investing activities		(2,641,477	)		(2,095,090	)		(546,387	)

FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt		3,494,196			805,008			2,689,188
Common stock and treasury stock		56,746			16,149			40,597
Retirement of long-term debt		(2,872,364	)		(1,567,420	)		(1,304,944	)
Repurchase of common stock		(665,624	)		(657,397	)		(8,227	)
Redemption of preferred stock		-			(1,847	)		1,847
Changes in credit line borrowings - net		(43,932	)		30,000			(73,932	)
Dividends paid:
Common stock		(595,461	)		(577,191	)		(18,270	)
Preferred stock		(20,013	)		(19,990	)		(23	)
Net cash flow used in financing activities		(646,452	)		(1,972,688	)		1,326,236

Effect of exchange rates on cash and cash equivalents		(848	)		1,825			(2,673	)

Net increase (decrease) in cash and cash equivalents		800,139			(1,425,108	)		2,225,247

Cash and cash equivalents at beginning of period		1,130,780			2,555,888			(1,425,108	)

Cash and cash equivalents at end of period	$	1,930,919		$	1,130,780		$	800,139

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$	552,533		$	598,842		$	(46,309	)
Income taxes	$	57,106		$	28,196		$	28,910

Noncash financing activities:
Long-term debt retired (equity unit notes)		-		$	(500,000	)	$	500,000
Common stock issued in settlement of equity unit purchase contracts		-		$	500,000		$	(500,000	)
Proceeds from long-term debt issued for the purpose
of refunding prior long-term debt	$	150,000			-		$	150,000
Long-term debt refunded with proceeds from
long-term debt issued in prior period	$	(150,000	)		-		$	(150,000	)

ENTERGY CORP /DE/ - FORM 8-K - EX-99.1 - EARNINGS RELEASE - October 21, 2010

Attached files